Gas Conditioning System

ABSTRACT

The present invention provides a gas conditioning system for processing an input gas from a low temperature gasification system to an output gas of desired characteristics. The system comprises a two-stage process, the first stage separating heavy metals and particulate matter in a dry phase, and the second stage including further processing steps of removing acid gases, and/or other contaminants. Optional processes include adjusting the humidity and temperature of the input gas as it passes through the gas conditioning system. The presence and sequence of processing steps is determined by the composition of the input gas, the desired composition of output gas for downstream applications, and by efficiency and waste minimization.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of priority under 35 U.S.C. § 119(e)from U.S. Provisional Application Ser. No. 60/746,616, filed May 5,2006. This application also claims benefit of priority to InternationalPatent Application No. PCT/CA2006/000881, filed Jun. 5, 2006. Thisapplication also claims benefit of priority under 35 U.S.C. 119(e) fromU.S. Provisional Application Ser. No. 60/864,116, filed Nov. 2, 2006.This application also claims benefit of priority under 35 U.S.C. §119(e)from U.S. Provisional Application Ser. No. 60/911,179, filed Apr. 11,2007. This application also claims benefit of priority under 35 U.S.C.119(e) from U.S. Provisional Application Ser. No. 60/797,973, filed May5, 2006. The contents of all of the aforementioned applications arehereby expressly incorporated by reference in their entirety and for allpurposes.

FIELD OF THE INVENTION

The present invention pertains to the field of gas clean up andprocessing, and in particular to the separation of particulate matterand targeted chemical species from an input gas generated from a lowtemperature gasification system.

BACKGROUND OF THE INVENTION

Gasification is a process that enables the conversion of carbonaceousfeedstock, such as municipal solid waste (MSW) or coal, into acombustible gas. The gas can be used to generate electricity, steam oras a basic raw material to produce chemicals and liquid fuels.

Possible uses for the gas include: the combustion in a boiler for theproduction of steam for internal processing and/or other externalpurposes, or for the generation of electricity through a steam turbine;the combustion directly in a gas turbine or a gas engine for theproduction of electricity; fuel cells; the production of methanol andother liquid fuels; as a further feedstock for the production ofchemicals such as plastics and fertilizers; the extraction of bothhydrogen and carbon monoxide as discrete industrial fuel gases; andother industrial applications.

Generally, the gasification process consists of feeding carbonaceousfeedstock into a heated chamber (the gasifier) along with a controlledand/or limited amount of oxygen and optionally steam. In contrast toincineration or combustion, which operate with excess oxygen to produceCO₂, H₂O, SO_(x), and NOx, gasification processes produce a raw gascomposition comprising CO, H₂, H₂S, and NH₃. After clean-up, the primarygasification products of interest are H₂ and CO.

Useful feedstock can include any municipal waste, waste produced byindustrial activity and biomedical waste, sewage, sludge, coal, heavyoils, petroleum coke, heavy refinery residuals, refinery wastes,hydrocarbon contaminated soils, biomass, and agricultural wastes, tires,and other hazardous waste. Depending on the origin of the feedstock, thevolatiles may include H₂O, H₂, N₂, O₂, CO₂, CO, CH₄, H₂S, NH₃, C₂H₆,unsaturated hydrocarbons such as acetylenes, olefins, aromatics, tars,hydrocarbon liquids (oils) and char (carbon black and ash).

As the feedstock is heated, water is the first constituent to evolve. Asthe temperature of the dry feedstock increases, pyrolysis takes place.During pyrolysis the feedstock is thermally decomposed to release tars,phenols, and light volatile hydrocarbon gases while the feedstock isconverted to char.

Char comprises the residual solids consisting of organic and inorganicmaterials. After pyrolysis, the char has a higher concentration ofcarbon than the dry feedstock and may serve as a source of activatedcarbon. In gasifiers operating at a high temperature (>1,200° C.) or insystems with a high temperature zone, inorganic mineral matter is fusedor vitrified to form a molten glass-like substance called slag.

Since the slag is in a fused, vitrified state, it is usually found to benon-hazardous and may be disposed of in a landfill as a non-hazardousmaterial, or sold as an ore, road-bed, or other construction material.It is becoming less desirable to dispose of waste material byincineration because of the extreme waste of fuel in the heating processand the further waste of disposing, as a residual waste, material thatcan be converted into a useful syngas and solid material.

The means of accomplishing a gasification process vary in many ways, butrely on four key engineering factors: the atmosphere (level of oxygen orair or steam content) in the gasifier; the design of the gasifier; theinternal and external heating means; and the operating temperature forthe process. Factors that affect the quality of the product gas include:feedstock composition, preparation and particle size; gasifier heatingrate; residence time; the plant configuration including whether itemploys a dry or slurry feed system, the feedstock-reactant flowgeometry, the design of the dry ash or slag mineral removal system;whether it uses a direct or indirect heat generation and transfermethod; and the syngas cleanup system. Gasification is usually carriedout at a temperature in the range of about 650° C. to 1200° C., eitherunder vacuum, at atmospheric pressure or at pressures up to about 100atmospheres.

There are a number of systems that have been proposed for capturing heatproduced by the gasification process and utilizing such heat to generateelectricity, generally known as combined cycle systems.

The energy in the product gas coupled with substantial amounts ofrecoverable sensible heat produced by the process and throughout thegasification system can generally produce sufficient electricity todrive the process, thereby alleviating the expense of local electricityconsumption. The amount of electrical power that is required to gasify aton of a carbonaceous feedstock depends directly upon the chemicalcomposition of the feedstock.

If the gas generated in the gasification process comprises a widevariety of volatiles, such as the kind of gas that tends to be generatedin a low temperature gasifier with a “low quality” carbonaceousfeedstock, it is generally referred to as off-gas. If thecharacteristics of the feedstock and the conditions in the gasifiergenerate a gas in which CO and H₂ are the predominant chemical species,the gas is referred to as syngas. Some gasification facilities employtechnologies to convert the raw off-gas or the raw syngas to a morerefined gas composition prior to cooling and cleaning through a gasquality conditioning system.

Utilizing plasma heating technology to gasify a material is a technologythat has been used commercially for many years. Plasma is a hightemperature luminous gas that is at least partially ionized, and is madeup of gas atoms, gas ions, and electrons. Plasma can be produced withany gas in this manner. This gives excellent control over chemicalreactions in the plasma as the gas might be neutral (for example, argon,helium, neon), reductive (for example, hydrogen, methane, ammonia,carbon monoxide), or oxidative (for example, oxygen, carbon dioxide). Inthe bulk phase, a plasma is electrically neutral.

Some gasification systems employ plasma heat to drive the gasificationprocess at a high temperature and/or to refine the offgas/syngas byconverting, reconstituting, or reforming longer chain volatiles and tarsinto smaller molecules with or without the addition of other inputs orreactants when gaseous molecules come into contact with the plasma heat,they will disassociate into their constituent atoms. Many of these atomswill react with other input molecules to form new molecules, whileothers may recombine with themselves. As the temperature of themolecules in contact with the plasma heat decreases all atoms fullyrecombine. As input gases can be controlled stoichiometrically, outputgases can be controlled to, for example, produce substantial levels ofcarbon monoxide and insubstantial levels of carbon dioxide.

The very high temperatures (3000 to 7000° C.) achievable with plasmaheating enable a high temperature gasification process where virtuallyany input feedstock including waste in as-received condition, includingliquids, gases, and solids in any form or combination can beaccommodated. The plasma technology can be positioned within a primarygasification chamber to make all the reactions happen simultaneously(high temperature gasification), can be positioned within the system tomake them happen sequentially (low temperature gasification with hightemperature refinement), or some combination thereof.

The gas produced during the gasification of carbonaceous feedstock isusually very hot but may contain small amounts of unwanted compounds andrequires further treatment to convert it into a useable product. Once acarbonaceous material is converted to a gaseous state, undesirablesubstances such as metals, sulfur compounds and ash may be removed fromthe gas. For example, dry filtration systems and wet scrubbers are oftenused to remove particulate matter and acid gases from the gas producedduring gasification. A number of gasification systems have beendeveloped which include systems to treat the gas produced during thegasification process.

These factors have been taken into account in the design of variousdifferent systems which are described, for example, in U.S. Pat. Nos.6,686,556, 6,630,113, 6,380,507; 6,215,678, 5,666,891, 5,798,497,5,756,957, and U.S. Patent Application Nos. 2004/0251241, 2002/0144981.There are also a number of patents relating to different technologiesfor the gasification of coal for the production of synthesis gases foruse in various applications, including U.S. Pat. Nos. 4,141,694;4,181,504; 4,208,191; 4,410,336; 4,472,172; 4,606,799; 5,331,906;5,486,269, and 6,200,430.

Prior systems and processes have not adequately addressed the problemsthat must be dealt with on a continuously changing basis. Some of thesetypes of gasification systems describe means for adjusting the processof generating a useful gas from the gasification reaction. Accordingly,it would be a significant advancement in the art to provide a systemthat can efficiently gasify carbonaceous feedstock in a manner thatmaximizes the overall efficiency of the process, and/or the stepscomprising the overall process.

Gas generated from a gasification reactor may contain heavy metalcontaminants such as cadmium, mercury and lead. These heavy metals haveemission limits, so before sending gas to downstream applications theheavy metals must be separated from the gas to meet the emission limitsfor these heavy metals. Examples of emission limits for heavy metals areas follows:

TABLE 1 Emission limits for heavy metals Heavy Metals Emission LimitsCadmium 14 μg/Rm³ Lead 142 μg/Rm³  Mercury 20 μg/Rm³

The composition of the raw gas resulting from coal gasification variesdepending on the conditions under which the converter is operated.Common components in the raw gas include combustibles (CO and H₂),non-combustibles (CO₂, N₂ and H₂O), air pollutants (heavy metals, NOx,H₂S, HCl, tars), and entrained solids. Prior to use of the product gasfor combustion, generation of electricity, or other applications, theproduct gas must be processed or refined in order to produce a gas withdesired characteristics for the application. Such processing or refininggenerally involves the removal of heavy metals and acid gases from theproduct gas.

When the gas is generated from the conversion of municipal solid waste(MSW) in a gasification system the gas contains metal and metalliccompounds in both combustible and non-combustible fractions. Normally,lead concentration in the waste is two orders of magnitude higher thancadmium and mercury. Distribution of heavy metals between variousresidues depends on MSW composition, physiochemical properties of metalsand their metallic compounds and the gasification process operatingconditions.

Metal compounds with high vapour pressure (Low boiling point) enter theatmosphere easily after being evaporated and are found mostly in productgas. Toxic heavy metal fumes result from volatilization of metallicconstituents followed by the condensation of vapour. Since each load ofMSW is different from the previous one, it is almost impossible to knowthe exact heavy metal concentration in the gasification process. Anestimate of the average heavy metal concentration in gas generated froma gasification process is shown below.

TABLE 2 Estimate of Heavy Metal Concentration in Syngas Heavy MetalConcentration in Syngas Cadmium 2.9-3.9 mg/Nm³ Lead 106-147 mg/Nm³ Mercury 1.3-1.7 mg/Nm³

Gas conditioning systems for cleaning gas produced by gasificationsystems have been described. U.S. Patent Application No. 20040251241describes the use of conventional gas cleaning technology that can beused to remove acid gases from a mixed gas stream.

U.S. Patent Application No. 20040031450 describes a gasification systemthat uses an acoustic pressure wave to cause agglomeration of particlescontained within the combustion stream for easy removal. In oneembodiment, a sulphur capturing agent is injected into the fluid channelfor not only removing sulphur from the combustion product stream but foralso facilitating particle agglomeration.

U.S. Patent Application No. 20040220285 describes a method and systemfor gasifying biomass. The resulting synthesis gas is passed through asaturation device and an absorption device, both of which are fed withoil. In this way the synthesis gas is scrubbed with oil and tar issubstantially removed therefrom.

U.S. Patent Application No. 20040247509 describes a gas cleaning systemfor use at high temperatures (between about 1,200° F. to about 300° F.)to remove at least a portion of contaminants such as halides, sulphur,particulates, mercury and others from a syngas. The gas cleaning systemmay include one or more filter vessels coupled in series for removinghalides, particulates, and sulphur from the syngas, and is operated byreceiving gas at a first temperature and pressure and dropping thetemperature of the syngas as the gas flows through the system. Theparticles removed by the first filter vessel can be sent to a collectionhopper where they can be separated into char particles and sorbentparticles. The char particles can be returned to the gasifier and thehalide laden sorbent can be disposed of or recycled by adding it to thegas entering the first filter vessel. Return of the char particles tothe gasifier will require an additional dedicated inlet for addition ofthe char particles. The gas cleaning system may be used for applicationsrequiring clean syngas such as fuel cell power generation, IGCC powergeneration, and chemical synthesis.

This background information is provided for the purpose of making knowninformation believed by the applicant to be of possible relevance to thepresent invention. No admission is necessarily intended, nor should beconstrued, that any of the preceding information constitutes prior artagainst the present invention.

SUMMARY OF THE INVENTION

An object of the present invention is to provide a gas conditioningsystem. In accordance with an aspect of the present invention, there isprovided a gas conditioning system for conditioning an input gas fromone or more locations within a gasification system to provide aconditioned gas, said gas conditioning system comprising: (a) a firstgas conditioner comprising one or more particle removal units forremoving particulate matter from the input gas in a first conditioningstage to provide a conditioned gas and removed particulate matter; (b) asolid residue conditioner for receiving and processing said removedparticulate matter to produce a secondary gas and solid waste; and (c) asecond gas conditioner operatively associated with said solid residueconditioner, said second gas conditioner comprising a gas cooler and oneor more further particle removal units for removing particulate matterfrom said secondary gas to provide a partially conditioned secondarygas, said second gas conditioner configured to pass said secondary gasthrough said gas cooler for cooling prior to entry of the secondary gasinto the one or more further particle removal units and to pass saidpartially conditioned secondary gas to the first gas conditioner forfurther processing.

In accordance with another aspect of the invention, there is providedprocess for providing a conditioned gas from an input gas from one ormore locations within a gasification system, said process comprising thefollowing steps: (a) removing particulate matter from said input gas ina first gas conditioner in a first conditioning stage to provide aconditioned gas and removed particulate matter; (b) transferring theremoved particulate matter to a solid residue conditioner and meltingthe removed particulate matter to produce a solid waste and a secondarygas; (c) conditioning said secondary gas in a second gas conditioner bycooling and removing particulate matter from said secondary gas toprovide a partially conditioned secondary gas; and (d) transferring saidpartially conditioned secondary gas to said first gas conditioner forfurther conditioning.

BRIEF DESCRIPTION OF THE FIGURES

These and other features of the invention will become more apparent inthe following detailed description in which reference is made to theappended drawings.

FIG. 1 presents a process flow diagram of a gas conditioning system(GCS) according to one embodiment of the invention.

FIG. 2 depicts a process flow diagram of a GCS according to oneembodiment of the invention.

FIG. 3 depicts a process flow diagram of a GCS according to oneembodiment of the invention.

FIG. 4 depicts a process flow diagram of a GCS according to oneembodiment of the invention.

FIG. 5 depicts a process flow diagram of a GCS according to oneembodiment of the invention.

FIG. 6 depicts a process flow diagram of a GCS according to oneembodiment of the invention.

FIG. 7 depicts a process flow diagram of a GCS according to oneembodiment of the invention.

FIG. 8 presents a process flow diagram of the processing steps carriedout by a GCS according to one embodiment of the invention.

FIG. 9 depicts a process flow diagram of the processing steps carriedout by a GCS according to one embodiment of the invention.

FIG. 10 depicts an overview process flow diagram of a low-temperaturegasification facility incorporating an exemplary GCS system according toone embodiment of the invention, integrated with a downstreamapplication (gas engines).

FIG. 11 depicts an alternate overview process flow diagram of alow-temperature gasification facility incorporating an exemplary GCSsystem according to one embodiment of the invention, integrated with adownstream application (gas engines).

FIG. 12 presents an exemplary schematic diagram of a portion of a GCSaccording to an embodiment of the invention, showing a dry injectionsystem in combination with a particle removal means.

FIG. 13 presents an exemplary schematic diagram of a portion of a GCSaccording to an embodiment of the invention, showing an HCl scrubber andassociated components.

FIG. 14 shows a system for collecting and storing waste water from theGCS, according to one embodiment.

FIG. 15 depicts a process flow diagram of an H₂S removal process usingThiopaq according to one embodiment of the invention.

FIG. 16 depicts a GCS according to one embodiment integrated with asyngas regulation system.

FIG. 17 depicts a GCS according to one embodiment of the invention.

FIG. 18 depicts a high-level process control schematic for a MunicipalSolid Waste Gasification Plant comprising a GCS according to oneembodiment of the invention.

FIG. 19 depicts an overview process flow diagram of a low-temperaturegasification facility incorporating an exemplary GCS system according toone embodiment of the invention, integrated with a downstreamapplication (gas engines).

FIG. 20 depicts an alternate overview process flow diagram of alow-temperature gasification facility incorporating an exemplary GCSsystem according to one embodiment of the invention, integrated with adownstream application (gas engines).

FIG. 21 is a schematic representation of a solid residue conditioningchamber that can be incorporated into the GCS in one embodiment of thepresent invention.

FIG. 22 is a schematic depiction of a residue conditioning chamberincorporated into a GCS in one embodiment of the invention, in which thechamber is in indirect communication with a baghouse filter of the GCSand a gasifier.

FIG. 23 depicts a partial cross-sectional view of an S-spout type slagoutlet of a solid residue conditioner suitable for incorporation into aGCS in one embodiment of the invention.

FIG. 24 depicts a partial cross-sectional view of a tiltable slagcrucible in a residue conditioning chamber suitable for incorporationinto a GCS in one embodiment of the invention.

FIG. 25 A to D depict partial cross-sectional views of various slagoutlets that can be used in a residue conditioning chamber forincorporation into a GCS in various embodiments of the invention.

DETAILED DESCRIPTION OF THE INVENTION

The present invention provides a two-stage gas conditioning system (GCS)for conditioning gas generated at one or more locations within agasification facility. The initial stage (Stage One) of the conditioningprocess comprises a dry phase separation of particulate matter from gasproduced by a converter and the second stage (Stage Two) of theconditioning process comprises one or more further processing steps toprovide a conditioned gas that meets the required and/or specified gascharacteristics. In facilities where gas is generated in more than onelocation, the gas conditioning process can comprise separate and/orcombinatory process streams. The GCS further comprises a control systemto control and optimize the conditioning process.

In one embodiment of the present invention, the GCS comprises twointegrated subsystems: a Converter gas conditioner (GC) and a SolidResidue gas conditioner (GC). The Converter GC processes gas emanatingfrom one or more points in the main gasification chamber(s) (or“converter(s)”). The Solid Residue GC processes gas emanating from themelting of solid residue collected from the converter and, optionally,from the Converter GC.

In a specific embodiment, Stage One conditioning by the GCS furthercomprises the passing the particulate matter separated during this Stageinto a solid residue conditioner that melts the particulate matter. Inaccordance with this embodiment, gas produced from the solid residuemelting step is then passed through a Solid Residue GC. The solidresidue conditioner can be a dedicated solid residue conditioner thatreceives particulate matter only from the Converter GC, or it can be ashared solid residue conditioner that receives particulate matter fromthe Converter GC and from the converter.

In one embodiment of the present invention, removal of particulatematter and at least a portion of the heavy metal contaminants in the dryStage One conditioning processes and the additional processing of theparticulate matter produced from the Stage One processes decreases theamount of hazardous waste that is generated during the conditioningprocess such that it is a small fraction by percentage or weight of thefeedstock fed into the converter.

DEFINITIONS

Unless defined otherwise, all technical and scientific terms used hereinhave the same meaning as commonly understood by one of ordinary skill inthe art to which this invention belongs.

As used herein, the term “partially conditioned gas” refers to gas thathas been processed through Stage One of the gas conditioning system(GCS) of the invention.

As used herein, the term “contaminant” refers to a material, such as acompound, an element, a molecule, or a combination of molecules up toand including particulate matter, that are present in an input gas andare not desired in the final conditioned gas. The contaminants can besolid, liquid or gaseous. For example, when the input gas is a syngasproduced from the conversion of carbonaceous feedstock into a gasproduct in a gasification system or converter, the input gas may containcontaminants such as sulphur, halide species, slag and charparticulates, nitrogen species (such as ammonia and hydrogen cyanide),and heavy metals (such as mercury, arsenic, and selenium).

As used herein, the term “about” refers to approximately a +/−10%variation from the stated value.

The term “secondary gas stream,” as used herein, refers to a gas that isgenerated in a solid residue conditioner from material (including, forexample, particulate matter and heavy metal diverted from a convertergas conditioner) that is processed in said solid residue conditioner.

The terms “solid phase” and “dry phase,” as used herein with respect toseparation of contaminants from an input gas refers to a separation thatis carried out without the addition of water or any aqueous solution andthe contaminants are separated from the input gas in an essentially dryor solid form.

The term “wet phase” as used herein with respect to separation ofcontaminants or heavy metals/particulate matter from an input gas refersto a separation that is carried out with addition of water or an aqueoussolution. This separation results in the separation of the contaminantsincluding heavy metals/particulate matter into the water or aqueoussolution.

Gas Conditioning System (GCS)

The present invention provides a gas conditioning system (GCS) forconditioning gas in a two-stage conditioning process and provides afinal conditioned gas that has an appropriate composition for thedesired downstream application. Stage One comprises one or more initialdry/solid phase separation steps followed by Stage Two, comprising oneor more further processing steps. In general, in the dry/solid phaseseparation steps, a substantial proportion of the particulate matter anda large proportion of heavy metal contaminants are removed. In StageTwo, additional amounts of particulate matter and heavy metalcontaminants as well as optionally other contaminants present in the gasare removed. Thus, the GCS comprises various components that carry outprocessing steps, separate particulate matter, acid gases, and/or heavymetals from the input gas and that, optionally, adjust the humidity andtemperature of the gas as it passes through the GCS. The GCS furthercomprises a control system to control and optimize the overallconditioning process.

The GCS receives an input gas, directly or indirectly, from one or morelocations within the gasification system and treats it through Stage Oneand Stage Two processes to produce a conditioned gas having a desiredcomposition. The GCS can be configured to produce a conditioned gas thatis suitable for use in downstream applications including, for example,as a fuel source for internal combustion engines, steam-injected gasturbines, combustion turbine engines, and fuel cell technologies; forthe synthesis of chemicals such as ethanol, methanol, and hydrocarbons,and of gases such as hydrogen, carbon monoxide, methane.

In one embodiment, the components of the GCS and the order of each ofthe processing steps are selected to minimize generation of hazardouswaste that must be treated and/or disposed of. The presence and sequenceof the processing steps can be selected, for example, based on thecomposition of the input gas and the composition of the conditioned gasrequired for the selected downstream application.

The GCS can be incorporated into any gasification facility wherein gasthat requires conditioning is generated at one or more points in thegasification system. As noted above, in one embodiment, the GCScomprises two integrated subsystems: a Converter GC and a Solid ResidueGC. The Solid Residue GC processes gas emanating from the solid residueusing the same or similar processing steps as the Converter GC, i.e.Stage One processing accomplishes the removal of at least a portion ofheavy metals and the majority of the particulate matter from the gas,followed by Stage Two processing to provide a conditioned gas that meetsthe downstream gas quality specifications.

In accordance with this embodiment, the Converter GC and the SolidResidue GC can operate in parallel wherein both subsystems are capableof conducting both Stage One and Stage two processes, or the twosubsystems can operate in a convergent manner, wherein they share someor all of the components for Stage Two processing. One embodiment of theinvention in which the two subsystems operate in a convergent manner isdepicted in FIG. 2 and described in detail in Example 1.

In some embodiments, the particulate matter separated in Stage One canbe further processed to reduce the amount of hazardous material thatmust be handled. FIG. 1 depicts a specific embodiment of the presentinvention in which Stage One further comprises transferring the solidmatter from the particulate and heavy metal removal step of theConverter GCS Stage One processing 135 to a solid residue conditioningchamber 165 where it can be melted and captured within inert slag 166.Gas from the melting step is then passed through a Solid Residue GCS 19,which comprises a gas cooler 170 and heavy metal and particulate matterremoval 185. Activated carbon and/or other sorbents can optionally beadded at 172 prior to particulate matter removal. The partiallyconditioned gas is then returned to the Converter GCS 28 either at 129prior to the Stage One processing 135, or at 131 after the Stage Oneprocessing 135, for Stage Two processing 141. Alternatively, in oneembodiment, the Solid Residue GC 19 can comprise components for parallelStage Two processing.

In one embodiment of the present invention, the amount of hazardouswaste produced by the GCS is less than about 5% of the weight ofcarbonaceous feedstock used. In one embodiment, the amount of hazardouswaste produced is less than about 2% of the weight of carbonaceousfeedstock used. In one embodiment, the amount of hazardous wasteproduced is less than 1% of the weight of carbonaceous feedstock used.In one embodiment, the amount of hazardous waste produced is betweenabout 1 kg and about 5 kg per 1 tonne of carbonaceous feedstock used. Inone embodiment, the amount of hazardous waste produced is between about1 kg and about 3 kg per 1 tonne of carbonaceous feedstock used. In oneembodiment, the amount of hazardous waste produced is between about 1 kgand about 2 kg per 1 tonne of carbonaceous feedstock used.

Various non-limiting embodiments of the GCS of the present invention areshown in FIGS. 1 to 9 and described below in Examples 1-11, 13 and 14.

The GCS can be configured for use with either a high temperaturegasification system or a low temperature gasification system. Oneembodiment of a GCS configured for use with a high temperaturegasification system is illustrated in FIG. 3 and described in Example 3,below. GCSs capable of operating at high temperatures, for example, inwhich contaminants are removed at temperatures above 700° C., can beuseful where large capacity applications are required.

The GCS can be configured such that one or more processing step isconducted using input gas at high temperature, with subsequent stepsbeing conducted at lower temperatures. One embodiment of a GCSconfigured to conduct at least one processing step at high temperatureis shown in FIG. 6 and described in Example 6, below.

In one embodiment of the present invention, the GCS is configured foruse with a low temperature gasification system. In one embodiment of thepresent invention, the first processing step employed by the GCS inStage One takes place below about 750° C. In one embodiment, the firstprocessing step in Stage One takes place below about 700° C. In oneembodiment, the first processing step in Stage One takes place belowabout 600° C. In one embodiment, the first processing step in Stage Onetakes place below about 500° C. In one embodiment, the first processingstep in Stage One takes place below about 400° C. In one embodiment, thefirst processing step in Stage One takes place below about 300° C. Inone embodiment, the first processing step in Stage One takes place belowabout 275° C. In one embodiment, the first processing step in Stage Onetakes place below about 260° C.

In one embodiment, the majority, i.e. more than half, of the Stage Oneand Stage Two processes employed by the GCS take place at lowtemperature, for example, at or below about 750° C. In one embodiment,the majority of the Stage One and Stage Two processes take place belowabout 700° C. In one embodiment, the majority of the Stage One and StageTwo processes take place below about 400° C. In one embodiment, themajority of the Stage One and Stage Two processes take place below about300° C. In one embodiment, the majority of the Stage One and Stage Twoprocesses take place below about 275° C. In one embodiment, the majorityof the Stage One and Stage Two processes take place below about 260° C.In one embodiment, the majority of the Stage One and Stage Two processestake place below about 240° C. In one embodiment, the majority of theStage One and Stage Two processes take place below about 200° C. In oneembodiment, the majority of the Stage One and Stage Two processes takeplace below about 100° C.

In one embodiment, the GCS is operated at a pressure close toatmospheric.

Input Gas

In general, the GCS is configured for the conditioning of an input gasthat is a gas produced from the conversion of carbonaceous feedstock,including, but not limited to, municipal solid waste, coal, biomass, andthe like, into a gas product in a gasification system (or “converter”).Typically, the main components of the gas as it leaves a gasificationsystem are carbon monoxide, nitrogen, carbon dioxide, hydrogen, andwater. Much smaller amounts of methane, ethylene, hydrogen chloride andhydrogen sulfide may also be present.

The exact proportions of the different chemical constituents depend onthe type of feedstock used. For example, gas produced from coal (whichis generally considered to be a relatively even composition ofcarbonaceous feedstock compared to municipal solid waste), under aspecific set of operating conditions, can yield 26% carbon monoxide,11.5% carbon dioxide, 28% hydrogen and about 31% water vapour.Gasification of sub-bituminous coal (23.1 MJ/kg-25.1% moisture content),under another set of operating conditions, yields 18.2%, 6.9%, 17.8% and15.1%, carbon monoxide, carbon dioxide, hydrogen and water,respectively. As known in the art, there are several different types ofcoal, ranging from peat to lignite (moisture around 70%, energy contentaround 8-10 MJ/kg), to black coal (moisture around 3% and energy contentabout 24-28 MJ/kg) to anthracite (virtually no moisture and energycontent up to about 32 MJ/kg), that may each exhibit substantialvariability in the product gas.

In cases where a gas is generated by the gasification of carbonaceousfeedstock, there exists certain amounts of contaminants which are notsuitable for normal and safe use of the gas in downstream applications.Accordingly, in one embodiment, the GCS of the present invention is usedto convert gas generated within a gasification converter into a gassubstantially diminished in the amounts of particulate matter, unwantedchemical contaminants such as acids, toxic chemicals (mercury, cadmium,and the like) and other substances. Effective removal of theseimpurities will render the gas suitable for use in downstreamapplications. In some applications it is desired that the output gas isclean and dry.

Stage One: Dry Phase Removal of Particulate Matter and Heavy Metals

Stage One of the GCS comprises components for implementing one or moredry or solid phase processing steps that remove at least a portion ofthe heavy metals and a majority of the particulate matter from the inputgas. Suitable solid phase processing steps are known in the art, andnon-limiting examples of means suitable for implementing such steps aredescribed below. In one embodiment, the portion of the heavy metals andmajority of the particulate matter from the input gas are removed fromthe input gas in a dry or solid form.

For example, heavy metal removal can be achieved using one or more solidphase separation components known in the art. Non-limiting examples ofsuch solid phase separation components include dry injection systems,particle removal units, activated carbon filtration components, andcomponents that allow contact with specialized sorbents, such aszeolites and nanostructures. Selected representative examples aredescribed in additional detail below. As is known in the art, theseparticulate separation components can be used to remove or separateparticulate matter/heavy metals in the solid/dry phase, for example, indry injection processes, activated carbon filtration, dry scrubbing,various particle removal processing steps and other dry or solid phaseprocessing steps known in the art.

In one embodiment of the present invention, Stage One of the GCScomprises at least one particle removal units. In another embodiment,Stage One of the GCS comprises one or more particle removal units and atleast one other component for implementing dry or solid phase processingsteps. In one embodiment, Stage One of the GCS comprises a dry injectionsystem and one or more particle removal units. FIG. 12 depicts Stage Oneof a GCS according to one embodiment of the invention, in which StageOne comprises a dry injection system 271 and a baghouse 230 forparticulates removal. The solid residue removed in the baghouse istransferred to a solid residue conditioner.

In embodiments where the input gas is a syngas exiting from a plasmagasification converter, the syngas can have a significant amount ofparticulate matter based on superficial velocity inside the converter.Thus, the GCS according to one embodiment of the present inventioncomprises particle removal unit(s) to remove particulate matter that maybecome entrained in the syngas exiting the gasification system. In oneembodiment in which coal is being used as a feedstock in a plasmagasification converter, the GCS comprises at least one particle removalunit.

Selection of the appropriate Stage One processing steps can be readilydetermined by one skilled in the art based on, for example, thecomposition of the input gas, the temperature of the input gas, thedesired composition of the final conditioned gas, the end use of thecomposition gas, as well as cost considerations and equipmentavailability. Stage One of the GCS can optionally comprise one or moregas coolers if required, for example, when the input gas is of hightemperature and the selected Stage One processes operate optimally at alower temperature.

As noted above, Stage One of the GCS provides for removal of themajority of the particulate matter and at least a portion of the heavymetal contaminants present in the input gas. In one embodiment, at leastabout 70% of the particulate matter present in the input gas is removedin Stage One. In one embodiment, at least about 80% of the particulatematter present in the input gas is removed in Stage One. In oneembodiment, at least about 90% of the particulate matter present in theinput gas is removed in Stage One. In one embodiment, at least about 95%of the particulate matter present in the input gas is removed in StageOne. In one embodiment, at least about 98% of the particulate matterpresent in the input gas is removed in Stage One. In one embodiment, atleast about 99% of the particulate matter present in the input gas isremoved in Stage One. In one embodiment, 99.5% of the particulate matterpresent in the input gas is removed in Stage One.

In one embodiment, at least about 50% of the heavy metal contaminantspresent in the input gas are removed in Stage One. In one embodiment, atleast about 60% of the heavy metal contaminants present in the input gasare removed in Stage One. In one embodiment, at least about 70% of theheavy metal contaminants present in the input gas are removed in StageOne. In one embodiment, at least about 80% of the heavy metalcontaminants present in the input gas are removed in Stage One. In oneembodiment, about 90% of the heavy metal contaminants present in theinput gas are removed in Stage One.

Dry Injection

Dry injection processes are known in the art and generally utilize acalculated amount of a suitable sorbent which is injected in the gasstream with enough residence time so that fine heavy metal particles andfumes can adsorb on the surface of the sorbent.

Heavy metals adsorbed on sorbent can be captured by a particle removalsuch as those described below, which removes heavy metals/particulatematter in the dry/solid phase and prevent it from moving through the GCSalong with the input gas. In one embodiment of the invention, the heavymetal particles adsorbed onto a suitable sorbent are captured using abaghouse filter.

Examples of suitable sorbents include, but are not limited to, activatedcarbon; promoted-activated carbon impregnated with iodine, sulphur, orother species; feldspar; lime; zinc-based sorbents; sodium-basedsorbents; metal oxide based sorbents; and other physical and chemicaladsorbents known in the art that are capable of effectively removingheavy metals such as mercury, arsenic, selenium and the like. Thesorbents may be a mesh size varying between a maximum size of about a 60mesh size and minimum size of about a 325 mesh size.

Injection is generally through a sorbent input means, such as a port,nozzle or tube, and can be achieved by gravity, locked hopper, or screwconveyor. The present invention also contemplates that the sorbent canbe provided within pipes that make up the GCS, for example in a pipeleading to a particle removal means, to be mixed with the input gas asit passes through the pipe. Other methods known in the art are alsoincluded.

The sorbents can be stored in one or more holding containers from whichthe sorbent(s) are delivered to the input means. The sorbent holdingcontainers can be part of the GCS or can be external to the GCS.

The GCS can comprise multiple sorbent input means or a single sorbentinput means. In those embodiments that comprise multiple sorbent inputmeans, each input means can add, or a sub-set of the input means caneach add, the same amount of sorbent. Alternatively, each input meanscan add, or a sub-set of the input means can each add, a differentamount of sorbent. Similarly, each input means can add, or a sub-set ofthe input means can each add, the same sorbent. Alternatively, eachinput means can add, or a sub-set of the input means can each add, adifferent sorbent. For example, each input means can add a differentratio of sorbent, with the goal of removing contaminants from the inputgas an economical and technical method, such as using both feldspar andactivated carbon as sorbents. In this case, removal of tars withfeldspar, can make the activated carbon more effective in removingmercury. The determination of the amount and type of sorbent(s) to usecan be readily determined by one of skill in the art based on thecontaminants present in the input gas and the desired constitution ofthe output gas.

As noted above, various combinations of sorbents can be injected intothe input gas by dry injection and suitable combinations can be readilydetermined by one of skill in the art based on, for example, thecomposition of the input gas. For example, activated carbon is usefulwhen the mercury present in the input gas is in non-elemental form;feldspar can be useful for input gases containing tar; combinations offeldspar and activated carbon

In one embodiment, feldspar is injected into the input gas. In oneembodiment, activated carbon is injected into the input gas. In oneembodiment, feldspar is used as a pre-coat for the particle removalmeans. In one embodiment, activated carbon is injected into the inputgas, and the particle removal means are precoated with feldspar. In oneembodiment, feldspar is continuously injected into the system.

Activated Carbon Filtration

Activated carbon filtration employing an activated carbon filter bed ora fluidized bed can be used as remove particulate matter or heavy metalsfrom the input gas. Input gas can be passed through an activated carbonbed that adsorbs heavy metals (mainly mercury) from the gas stream.

As is known in the art, the efficiency and/or effectiveness of carbonbed filters changes depending on the characteristics of the input gas,such as, for example, the temperature and/or humidity of the input gas.Typically, carbon bed filters are more efficient at lower temperatures,for example less than about 70° C., and/or if the relative humidity ofthe input gas is less than about 60%. Thus, in one embodiment of thepresent invention, in which a carbon bed filter is employed, the inputgas is submitted to a cooling and/or humidity control processing stepprior to passing through the filter bed.

As is known in the art, the use of activated carbon beds to remove largeamounts of particulate matter can be less efficient than other processesas particulate matter may build up in low flow areas and pressure dropchanges may occur as particulate matter fills the carbon bed. As such,in one embodiment of the present invention, an activated carbon bed isused in Stage One processing in conjunction with another dry processingstep that can facilitate the removal of heavy metals and/or particulatesfrom the input gas prior to it entering the activated carbon bed. Inanother embodiment of the present invention, an activated carbon bed isused in Stage Two processing, as described below.

Dry Scrubbing

Dry scrubbing is another processing step that is carried out in the dryphase, and is a processing step that removes sulphur, and optionallyparticulate matter and small amounts of mercury, from the input gas.

In a dry scrubbing process, particles of an alkaline sorbent areinjected into a gas, producing a dry solid by-product. The absorbentemployed in the dry scrubbing process can be characterized as either“once-through” or regenerable. Dry scrubbers systems can be grouped intothree categories: spray dryers, circulating spray dryers, and dryinjection systems.

In a spray dryer, a slurry of alkaline sorbent, such as lime or a sodiumbased sorbent, is atomized into the input gas to absorb thecontaminants. The resulting dry material, including fly ash, iscollected by a downstream particle removal means, such as anelectrostatic precipitator or fabric filter. Spray dryers commonly aredesigned for SO₂ removal efficiencies of about 70 to about 95%.

A circulating dry scrubber uses an entrained fluidized bed reactor forcontacting a sorbent, such as hydrated lime, with input gas. Theintensive gas-solid mixing that occurs in the reactor promotes thereaction of sulphur oxides in the gas with the dry lime particles. Themixture of reaction products (calcium sulphite/sulphate), unreactedlime, and fly ash is carried to a downstream particle removal means.Water spray can be introduced into the fluidized bed separately toenhance performance, for example, to maximise SO₂ capture with minimumlime utilization by optimizing the surface moisture content of the lime.Circulating dry scrubbers can provide removal efficiencies of more thanabout 90%.

Dry scrubbing can also employ dry injection processes, such as thosedescribed above, which involve the injection of a dry sorbent, such assoda ash, lime or limestone, into the input gas and subsequentcollection of the contaminant-laden sorbent in a downstream particleremoval means. Dry injection systems typically have removal efficienciesranging from 50-70%.

Particle Removal Units and Processes

In one embodiment, the GCS of the present invention includes one or moreparticle removal units which act to remove particulate matter from theinput gas. Particle removal means can also remove heavy metals, such aselemental mercury, from the input gas. In embodiments where dryinjection is employed in the GCS, the one or more particle removal unitsalso serve to remove contaminant-laden sorbents from the input gas.Examples of suitable particle removal units include, but are not limitedto, cyclone separators or filters, high temperature ceramic filters,moving bed granular filters, baghouse filters, and electrostaticprecipitators (ESP). In one embodiment of the present invention, the GCScomprises one or more particle removal units selected from a cyclonefilter, a high temperature ceramic filter and a baghouse filter. In oneembodiment, the GCS comprises a particle removal unit that can removeparticulate matter with 99.9% efficiency from input gas with as much as10 g/Nm3 particulate loading.

As is known in the art, the choice of particle removal unit will dependon, for example, the temperature of the input gas, the size of theparticulate matter to be removed, and, when applicable, the type ofsorbent injected into the gas stream. Suitable particle removal unitscan be readily selected by one of skill in the art.

As noted above, the particle removal units can be selected based on thesize of the particulates to be removed. For example, in one embodiment,the GCS comprises a cyclone separator or filter to remove coarseparticles (i.e. those greater than about 10 microns in size). In anotherembodiment, in which the temperature of the input gas is relativelyhigh, for example, above about 700° C., the GCS comprises a cyclonefilter. By way of example, the separation efficiency for hightemperature cyclone at various particle sizes is: 17.0% @ 2.5 μm, 39.3%@ 3.0 μm, 62.0% @ 3.5 μm, 79.0% @ 4.0 μm, 93.7% @ 6.0 μm and 98.5% @11.0 μm.

In another embodiment of the present invention, the GCS comprises an ESPor a baghouse filter for removal of smaller or finer particles, forexample, those less than about 1 μm. As is known in the art, ESP isdriven by an electrostatic field and, therefore, when used with gasstreams of high oxygen content should include control mechanisms to tripthe current if the oxygen content reaches a specified level.

Cloth collectors such as baghouse filters can collect particles of asize down to about 0.01 microns, depending on the type of filteremployed. Baghouse filters are typically fabric filters, cellulosefilters or organic polymer-based filters. Other examples of filters thatcan be used in a baghouse context include, but are not limited to, linedand unlined fiberglass bags, Teflon lined bags and P84 basalt bags.Suitable filters can be readily selected by those of skill in the artbased on considerations such as, one or more of the temperature of theinput gas, the moisture levels in the baghouse and in the input gas, theelectrostatic nature of the particles in the input gas, acid and/oralkali chemical resistance of the filter, the ability of the filter torelease the filter cake, filter permeability and the size of theparticles.

In one embodiment of the present invention, the GCS comprises a baghousefilter and is configured such that the temperature of the gas enteringthe baghouse is between about 180° C. and about 280° C. As is known inthe art, operating a baghouse filter at a higher temperature candecrease the risk of tars in the input gas plugging the filters andreducing efficiencies. Higher temperatures can reduce the efficiency ofparticle removal by the baghouse filters, for example, increasing theoperating temperature from 200° C. to 260° C. decreases particle removalefficiency from 99.9% to 99.5%. Thus, when higher operating temperaturesare selected for a baghouse filter comprised by the GCS, the GCS cancomprise additional downstream components, either in Stage One or StageTwo, to capture remaining particulates. For example, wet scrubbers andactivated carbon beads can be included for removal of particulates inaddition to other contaminants. In one embodiment of the presentinvention in which the GCS comprises a baghouse filter, the GCS isconfigured such that the temperature of the gas entering the baghouse isbetween about 250° C. and about 260° C. In another embodiment in whichthe GCS comprises a baghouse filter, the GCS is configured such that thetemperature of the gas entering the baghouse is between about 190° C.and about 210° C.

In one embodiment of the present invention, Stage One of the GCScomprises one particle removal unit for removal of particulate matter.In one embodiment of the present invention, Stage One of the GCScomprises two particle removal units for removal of particulate matter.In one embodiment of the present invention, Stage One of the GCScomprises a first particle removal unit for removal of coarse particles,and a second particle removal unit for removal of smaller or finerparticles. In one embodiment of the present invention, Stage One of theGCS comprises a cyclone filter as a first particle removal unit, whichcan remove particles larger than about 5 to about 10 microns in size. Inone embodiment of the present invention, Stage One of the GCS comprisesa baghouse filter as a first particle removal unit. In one embodiment ofthe present invention, Stage One of the GCS comprises a baghouse filteras a second particle removal unit.

Optional Gas Cooler

As noted above, the performance of a given particle removal unit may beinfluenced by the temperature of the input gas. As such, depending onthe specific particle removal unit employed, a gas cooling system may beused to cool the input gas before it enters the particle removal unit.For example, as is known in the art, cooling of the input gas may be ofparticular importance when a baghouse type filter is used forparticulate removal, since baghouse type filters often cannot withstandextremely high temperatures.

In accordance with one embodiment of the present invention, the GCS isconfigured to process input gas for which the temperature has beenreduced by passing the input gas through a gas cooler prior to entryinto the GCS. In another embodiment of the present invention, the GCScomprises one or more gas coolers for reducing the temperature of theinput gas prior to entry into Stage One processing. In anotherembodiment, Stage One of the GCS is configured to process input gas thetemperature of which has been reduced initially by a gas cooler externalto the GCS and then further by a gas cooler comprised by the GCS.Suitable gas coolers for incorporation into the GCS are known in the artand include, but are not limited to, heat exchangers, quenchers and thelike. Other options for the gas coolers are described below in thesection “Additional Options.”

Solid Residue Conditioner

The GCS can optionally comprise a solid residue conditioner forreceiving and melting the solid residue produced during Stage Oneprocessing. The residue conditioner can be a dedicated residueconditioner that receives solid residue from Stage One processes of theGCS only, or it can be shared, for example, with other components of agasification system. In one embodiment, the solid residue conditioner isshared with a gasifier and, thus, receives solid residue both from theStage One processes of the GCS and from the gasification reaction thattakes place in the gasifier.

The solid residue conditioning process is accomplished by raising thetemperature of the residue in the conditioner to the level required tomelt the residue to form a vitreous material that cools to a densesolid. The high temperature also converts carbon in the residue to aresidue gas having a heating value. The solid residue conditioner,therefore, comprises a suitable heat source for melting the solidresidue, such as, for example, a thermal lamp, joule heater or plasmaheat. In one embodiment, the solid residue conditioner comprises asource of plasma heat, for example, one or more plasma torches.

The solid residue conditioner comprises a conditioning chamber adaptedto i) receive the solid residue, ii) heat the solid residue to form amolten slag material and a gaseous product having a heating value, andiii) exhaust the molten slag and gaseous product. Accordingly, the solidresidue conditioning chamber comprises a refractory-lined chamber havinga solid residue inlet, a gas outlet, a slag outlet, and a heat source.The solid residue conditioning chamber further optionally includes oneor more air and/or steam inlets.

The molten slag, at a temperature of, for example, about 1200° C. toabout 1800° C., may periodically or continuously be output from theconditioning (or residue) chamber and thereafter cooled to form a solidslag material. Such slag material may be intended for landfill disposalor may further be broken into aggregates for conventional uses.Alternatively, the molten slag can be poured into containers to formingots, bricks tiles or similar construction material. The resultingslag material may also be used as a supplementary cementing material inconcrete, in the production of a lightweight aggregate or mineral wool,in the manufacture of foam glass, or in the development of packagingmaterials. The composition of the resulting slag material may becontrolled through the addition of process additives to change meltingpoint and/or other properties of the slag. Such solid process additivesmay include, but are not limited to silica, alumina, lime or iron. Thesolid residue conditioner is therefore operatively associated with asubsystem for cooling the molten slag to its solid form. The slagcooling subsystem is provided as appropriate to afford the cooled slagproduct in the desired format.

In one embodiment, the residue conditioning chamber is designed toensure that the residue conditioning process is carried out efficientlyand completely, in order to use a minimum amount of energy to effectcomplete conditioning of the residue. Accordingly, factors such asefficient heat transfer, adequate heat temperatures, residence time,molten slag flow, input residue volume and composition, and size andinsulation of the chamber are taken into account when designing theresidue conditioning chamber. The chamber is also designed to ensurethat the residue conditioning process is carried out in a safe manner.Accordingly, the system is designed to isolate the residue conditioningenvironment from the external environment.

The residue conditioning chamber is provided with a heat source, such asa plasma heat source, that meets the required temperature for heatingthe residue to levels required to convert any remaining volatiles andcarbon to a gaseous product having a heating value and to melt andhomogenize the residue to provide a molten slag at a temperaturesufficient to flow out of the chamber. The chamber is also designed toensure highly efficient heat transfer between the plasma gases and theresidue, to minimize the amount of sensible heat that is lost via theproduct gas. Therefore, in one embodiment, the type of plasma heatsource used, as well as the position and orientation, of the plasmaheating means are additional factors to be considered in the design ofthe residue conditioning chamber.

The residue conditioning chamber is also designed to ensure that theresidue residence time is sufficient to bring the residue up to anadequate temperature for melting and homogenization, and to fullyconvert the carbon to the gaseous product. Accordingly, the chamber isprovided with a reservoir in which the residue accumulates while beingheated by the heat source. The reservoir also allows mixing of the solidand molten materials during the conditioning process. Sufficientresidence time and adequate mixing ensures that the conditioning processis completely carried out, and that the resulting slag and gaseousproducts have the desired composition.

The chamber is designed for continuous or intermittent output of themolten slag material. Continuous slag removal allows the conditioningprocess to be carried out on a continual basis, wherein the residue tobe conditioned may be continuously input and processed by the plasmaheat, without interruption for periodic slag removal.

In one embodiment, continuous slag exhaust is achieved by using areservoir bounded on one side by a weir that allows the slag pool toaccumulate until it exceeds a certain level, at which point the moltenslag runs over the weir and out of the chamber. In the embodimentdepicted in FIG. 21, the residue 4010 drops through a residue inlet 4012located at the top of the conditioning chamber 4020 into a reservoir4060, where it is conditioned by a plasma torch plume 4036. The moltenmaterials are held in the reservoir 4060 by a weir 4162 until the pool4044 reaches the top of the weir. Thereafter, as additional residueenters the system and is conditioned, a corresponding amount of moltenmaterial overflows the weir and out of the chamber through a slag outlet4042. A residue gas product 4954 exits the chamber via a gas outlet4052.

Where the residue being conditioned contains a significant amount ofmetal, and the residue conditioning chamber comprises a reservoirbounded by a weir, the metals, due to their higher melting temperatureand density, typically accumulate in the reservoir until such time asthey are removed. Accordingly, in one embodiment of the presentinvention, the reservoir is optionally provided with a metal tap port,whereby the tap port is plugged with a soft refractory paste which maybe periodically removed using the heat from an oxygen lance. Once thetap port has been opened and the chamber temperature has been raisedsufficiently to melt the accumulated metals, the molten metals aretapped off from the bottom of the reservoir.

In one embodiment, the reservoir itself may also be provided with a slagoutlet adapted for continuous exhaust of the molten slag. In oneembodiment, the reservoir may also provide for intermittent slagremoval, wherein the reservoir is designed to allow the accumulation ofmolten materials until the conditioning process is complete, at whichpoint the molten slag is exhausted.

For example, in one embodiment, as depicted in FIG. 23, the molten slagis exhausted through an S-trap outlet 4142. In this embodiment, the slagoutput means may optionally comprise a burner 4138 or other heatingmeans located at or near the outlet 4142 in order to maintain thetemperature of the molten slag at the outlet 4142 high enough to ensurethat the outlet 4142 remains open through the complete slag extractionperiod. This embodiment also ensures that the level of the slag pool4144 does not go below a predetermined level, thereby keeping the meltenvironment sealed to avoid gaseous contact with the externalenvironment.

FIG. 24 illustrates one embodiment that may be provided to controllablyexhaust the molten slag from a reservoir by a tipping mechanism. In thisembodiment, the residue conditioning chamber 4320 has a tiltablecrucible 4362 comprising reservoir 4360, a spout 4342, a counterweight4368 and a lever arm 4364 provided as a mechanism for tilting thecrucible 4362.

FIG. 25A to D schematically illustrate portions of different designoptions that may be provided for controlled exhaust of the molten slagthrough an appropriately adapted outlet in the reservoir or chamber. Themolten slag exhaust may be controlled to ensure that the level of themolten slag is not allowed to reach below the top of the outlet, so thatgases from the external atmosphere do not enter the interior meltregion.

FIG. 25A depicts a reservoir or chamber having an outlet 4542 in a sidewall near the bottom of the reservoir/chamber. The outlet 4542 issurrounded by an induction heater 4538 enclosed in the refractory thatcan control the temperature of the refractory in the region surroundingthe outlet 4542. Increasing the temperature sufficiently to maintain theslag in the molten state allows the slag to flow though the outlet 4542.When the level of the slag pool 4544 reaches the desired level, theinduction heater 4538 is turned off, and the slag is allowed to solidifyin the outlet 4542.

FIG. 25B depicts one embodiment wherein the outlet 4442 is “plugged”with a soft refractory paste 4444. An oxygen lance 4438 is provided in aposition suitable to “burn” a hole into the soft refractory paste 4444allowing molten slag to pour out. The flow is stopped by placingrefractory or other suitable material back into the outlet 4442.

FIG. 25C depicts one embodiment wherein the outlet 4742 is covered by amovable water cooled plug 4744. The plug 4744 is movable from a closedposition to an open position, thereby exposing the outlet 4742 to allowthe molten slag to exhaust through the outlet 4742. The molten materialshould not adhere to the smooth surface of the plug 4744 because of thewater cooling effect.

FIG. 25C depicts one embodiment wherein the outlet 4642 is plugged by awedge-type device 4644. The “wedge” is pushed in and out of outlet 4642as required to control the exhaust of the molten slag.

Due to the very high temperatures needed to melt the residue, andparticularly to melt any metals that may be present, the residueconditioning chamber wall is lined with a refractory material that willbe subjected to very severe operational demands. The selection ofappropriate materials for the design of a residue conditioning chamberis made according to a number of criteria, such as the operatingtemperature that will be achieved during typical residue conditioningprocesses, resistance to thermal shock, and resistance to abrasion anderosion/corrosion due to the molten slag and/or hot gases that aregenerated during the conditioning process.

The inner refractory is selected to provide an inner lining having veryhigh resistance to corrosion and erosion, particularly at the slagwaterline, in addition to resistance to the high operating temperatures.The porosity and slag wetability of the inner refractory material mustbe considered to ensure that the refractory material selected will beresistant to penetration of the molten slag into the hot face. Thematerials are also selected such that secondary reactions of therefractory material with hydrogen are minimized, thereby avoiding apossible loss of integrity in the refractory and contamination of theproduct gas.

The residue conditioning chamber is typically manufactured with multiplelayers of materials as are appropriate. For example, the outer layer, orshell, of the chamber is typically steel. Moreover, it may be beneficialto provide one or more insulating layers between the inner refractorylayer and the outer steel shell to reduce the temperature of the steelcasing. Where a second layer (for example, an insulating firebricklayer) is provided, it may also be necessary to select a material thatdoes not react with hydrogen. An insulating board around the outersurface of the slag reservoir may also be provided to reduce thetemperature of the steel casing. When room for expansion of therefractory without cracking is required, a compressible material, suchas a ceramic blanket, can be used against the steel shell. Theinsulating materials are selected to provide a shell temperature highenough to avoid acid gas condensation if such an issue is relevant, butnot so high as to compromise the integrity of the outer shell.

The refractory material can therefore be one, or a combination of,conventional refractory materials known in the art which are suitablefor use in a chamber for extremely high temperature (e.g., a temperatureof about 1100° C. to 1800° C.) non-pressurized reaction. Examples ofsuch refractory materials include, but are not limited to, hightemperature fired ceramics (such as aluminum oxide, aluminum nitride,aluminum silicate, boron nitride, chromic oxide, zirconium phosphate),glass ceramics and high alumina brick containing principally, silica,alumina and titania.

Due to the severe operating conditions, it is anticipated that thereservoir refractory will require periodic maintenance. Accordingly, inone embodiment, the residue conditioning chamber is provided inseparable upper and lower portions, wherein the chamber lower portion(where the reservoir is located) is removable from the chamber upperportion. In one embodiment, the chamber is suspended from a supportstructure such that the lower portion can be dropped away from the upperportion to facilitate maintenance. This embodiment provides for removingthe lower portion without disturbing any connections between the chamberupper portion and upstream or downstream components of the system.

The residue conditioning chamber may also include one or more ports toaccommodate additional structural elements or instruments that mayoptionally be required. The chamber may also include service ports toallow for entry or access into the chamber for scrubbing/cleaning,maintenance, and repair. Such ports are known in the art and can includesealable port holes of various sizes. In one embodiment, the port may bea viewport that optionally includes a closed circuit television tomaintain operator full visibility of aspects of the residue processing,including monitoring of the slag outlet for formation of blockages.

In one embodiment of the present invention, the solid residueconditioner comprised by the GCS is configured to receive solid residuefrom Stage One processing in the Converter GC only. In anotherembodiment, the solid residue conditioner comprised by the GCS isconfigured to receive solid residue from Stage One processing in theConverter GC and solid residue from a converter that is generating theinput gas to be conditioned in the GCS.

FIG. 22 depicts a solid residue conditioner in one embodiment of thepresent invention in which the solid residue conditioning chamber 4520is indirectly connected to two sources of residue to be conditioned,where one source is a baghouse filter 6030 of Stage One of the GCS andthe other source is a carbonaceous feedstock gasifier 2000.

Stage Two: Further Processing

Stage Two of the GCS comprises one or more components for implementingfurther processing steps that remove additional amounts of particulatematter and heavy metal contaminants, and optionally other contaminantspresent in the input gas. Stage Two processes can include dry phaseseparation steps as described for Stage One, and/or other separationsteps including wet processing steps. Non-limiting examples of otherprocessing steps that may be implemented in Stage Two include processesthat remove acid gases, heavy metals and particulate matter, and othercontaminants such as dioxin, furan, CO₂, and ammonia. As is known in theart, various components can be used to carry out these processes,including various wet scrubbers (such as venturi scrubbers and impinjetscrubbers), chloride guard beds, wet ESP and the like. Stage Two canalso include cooling units and/or humidity controllers, as well as gasmoving units for ensuring that the input gas moves through the system.Examples of Stage Two processing steps, other than those alreadydescribed in Stage One, are described below.

Acid Gas Removal

Input gases to be processed in the GCS can include as contaminants acidgases such as HCl and H₂S. For example, syngas produced in agasification converter contains such acid gases. The concentrations ofthese acid gases in syngas can range from about 0.05 to about 0.5% forHCl, and from about 100 ppm to about 1000 ppm for H₂S, depending on thecarbonaceous feedstock used in the gasification process. The amount ofHCl and H₂S in the input gas can be calculated as is known in the art.In one embodiment, the GCS is configured to process input gas comprisingabout 0.178% of HCl and about 666 ppm (0.07%) of H₂S. In one embodiment,the GCS is configured to process input gas such that it meets Canadianemission limit for HCl and H₂S of about 5 ppm HCl and about 21 ppm H₂S.Thus, in one embodiment, the GCS is configured such that the conditionedgas exiting the GCS contains between about 20 ppm and about 5 ppm HCland between about 30 ppm and about 20 ppm H₂S.

Acid gas removal or separation can be achieved by dry scrubbing or wetscrubbing processes. Dry scrubbing processes are generally lessefficient than wet scrubbing processes. However, a dry scrubbingprocess, such as those described above for Stage One processes, can bechosen for embodiments of the GCS in which ease of handling is requiredif, for example, the waste water stream resulting from the dry scrubbingprocess needs to be disposed of as hazardous material.

Wet scrubbing processes utilise wet packed columns or towers thatprovide a large contact area for heat transfer and mass transfer withlow pressure drop that will aids in sub cooling of the gas. Theprinciple of wet scrubbers is to remove contaminants from the gas bypassing the gas through a packed structure which provides a large wettedsurface area to induce intimate contact between the gas and thescrubbing liquor. The contaminant is absorbed into or reacted with thescrubbing liquor. For removal of acid gases an alkaline solution is usedas the scrubbing liquor. Typically, sodium hydroxide is the alkalinesolution used for wet scrubbing. However, H₂S removal requires use ofhigh pH alkaline solution in the scrubbing step. If CO₂ is present inthe input gas, its affinity for alkaline solution results in removal ofCO₂ from the input gas, which may not be desirable, depending on thedownstream application the output gas is to be used for. Thus, theprocess selected for removal of the acid gases will depend on the enduse of the conditioned gas.

In addition to dry and wet scrubbing processes as described above, anumber of processing steps are known in the art for removing HCl vaporfrom gases. Non-limiting examples of such processing steps include:adsorption of the HCl on activated carbon or alumina, reaction withalkali or alkaline earth carbonates or oxides, the use of chlorideguards, and the use of high temperature sorbents such as alkali andalkaline earth compounds, shortite (Na₂CO₃.2CaCO₃) and trona(Na₂CO₃.NaHCO₃.2H₂O), eutectic melts of Li₂CO₃ and Na₂CO₃, and flue gassorbents such as alkalized alumina. In one embodiment, Stage Two of theGCS comprises an HCl scrubber for removal of HCl from the input gasusing alkaline solution.

In one embodiment, the GCS provides for removal of remaining particulatematter simultaneously with separation of acid gases from the input gas(for example during removal of HCl during the HCl scrubber step). IfStage One of this embodiment of the GCS did not include a baghouse orother fine particle removal unit, the resulting liquid waste stream willrequire water treatment for hazardous particulate removal.

H₂S may be removed from the input gas using various processes known inthe art including wet and dry scrubbing processes as outlined above.Suitable methods include for example, wet absorption with NaOH ortriazine, dry adsorption with Sufatreat, biological processes such asthe use of Thiopaq® scrubbers, or selective oxidation, including liquidredox (Low CAT). Physical solvent processes can also be used to separateH₂S from the input gas. Non-limiting examples of such physical solventthat can be used include polyethylene glycol derivatives such asSelexol®; fluor solvents such as anhydrous propylene carbonate; methanolas used in a Rectisol process.

In one embodiment, H₂S is removed from the synthetic gas using aThiopaq® scrubber. A Thiopaq® scrubber involves the use of a two stepprocess in which input gas is treated in a wet scrubber with a mildalkaline solution (at 8.5 to 9 pH) in order to absorb hydrogen sulfide(H₂S). The H₂S laden scrubber liquid is fed to a bioreactor where thesulphide is converted into elemental sulphur by a biological process,regenerating the scrubber liquid in the process, and enabling thebioreactor effluent to be recycled to the scrubber.

In one embodiment, the H₂S removal efficiency of the GCS is such thatthe output gas leaving the system and used in a downstream applicationsuch as a gas engine will produce SO₂ emission below between about 10ppm and about 30 ppm. In one embodiment, the H₂S removal efficiency issuch that the output gas leaving the system and used in a downstreamapplication such as a gas engine will produce SO₂ emission below 15 ppm.In one embodiment, the H₂S removal system is designed to produce outputgas with an H₂S concentration of about 20 ppm.

Heavy Metal/Particulate Matter Removal

Processes and particle removal units suitable for use in Stage Oneprocesses can also be used in Stage Two processes and have beendescribed above. In one embodiment, the GCS comprises a carbon bedfilter or mercury polisher as a particle removal unit in Stage Two.

As is known in the art, at a relative humidity (R.H.) of greater than50%, water will start to adsorb on the carbon of the carbon bed filterand obstruct diffusion, which affects removal performance. This can becorrected, however, by increasing bed depth. Carbon bed filters can alsobe used at higher relative humidities, for example between ˜70% R.H and100% R.H., when lower performance is acceptable as the performanceeffect is only seen when the desired final content of mercury in theconditioned gas is in the 0.001 to 0.01 ug/Nm3 mercury range. Forexample, when mercury concentrations of about 19 ug/Nm3 are acceptable,the higher R.H. ranges can be used.

In one embodiment, the GCS employs an activated carbon filter as a finalpolishing device for removal of mercury. In one embodiment, an activatedcarbon filter with 7-8 inches of Water Column pressure drop is used toachieve about 99.8% removal of mercury. As will be apparent to one ofskill in the art, particulate matter can also be extracted by carbonfilter beds in small amounts of small particles (<1 μm) that were notcaptured by any upstream particle removal unit. Particulate matter thatgets captured in Stage Two of the GCS can be disposed of in water orwith spent carbon removal).

In one embodiment, activated carbon bed filters are also used for heavymetal removal from waste water.

An acid scrubbing system can also be an effective technique to captureheavy metals. This requires the passage of the gas containing heavymetals through a packed column with low pH (normally 1-2) solutioncirculation. Heavy metals and heavy metal compounds react with acid toform their stable compounds. With this technique the heavy metalconcentration in the circulation solution will increase and thustreatment of the resulting waste water may be required. In oneembodiment, the GCS comprises an acid scrubbing system to remove heavymetals. Examples of acid scrubbing systems include packed tower, spraytower and tray tower, impinjet systems, froth spray systems which areall capable of removing the contaminants from the input gas.

Dioxin and Furan Removal

Dioxins and furans are some of the most undesirable and toxic compoundsassociated with heat treatment of waste. In order for these compounds tobe formed, all of the following conditions have to be present: atemperature in the range of 250-350° C., oxygen, carbon in flyash (actsas a catalyst especially if gas goes through the bed) and adequateresidence time. The GCS of the present invention is configured to try toeliminate or decrease the potential for their formation. Various stepscan be taken to minimise the occurrence of the required conditions fordioxin and furan formation. For example, any quenching steps can beconducted in a quencher or spray dryer absorber to ensure fast quenchingwhen taking the gas through the above temperature range, the presence ofoxygen and/or flyash can be minimised.

In embodiments where the input gas comprises dioxin and furan, he GCScan comprise an activated carbon injection step which will result in thedioxin and furan present in the gas being adsorbed to the carbonsurface. The carbon can then be removed by a suitable particle removalunit. In one embodiment, the GCS comprises a spray dryer absorber thatdecreases the residence time at the relevant temperature range tominimise the possibility of dioxin/furan formation.

Removal of Carbon Dioxide and Ammonia

The GCS can optionally include components for the removal of carbondioxide and/or ammonia if removal of these compounds is required.Suitable components are known in the art. As is also known in the art,ammonia can be removed from the input gas during the HCl scrubbing step.

Additional Options for the Process Cooling Units and HumidityControllers

Cooling units and/or humidity controllers can optionally be included inthe GCS as part of Stage One (as described above) or Stage Two. Suitablecomponents are known in the art and include, but are not limited to,evaporative cooling towers, gas coolers, chillers, recuperators, heatexchangers, indirect air to gas heat exchangers, and heat recovery steamgenerators (HRSGs). Recuperators and HRSGs can be used to cool the gaswhile utilizing the heat instead of dissipating it as is done byevaporative cooling towers, gas coolers, and chillers. Use of an HRSGleads to slower cooling of the gas, which is one of the four conditionsnecessary to be present simultaneously for the production of dioxins andfurans, as noted above. Thus, in embodiments where an HRSG is used, morecaution is exercised (for example, to ensure oxygen concentration islow) to avoid the possibility of introducing the other conditions(flyash presence and residence time).

Demisters/reheaters may be incorporated in the GCS for moisture removaland/or prevention of condensation as is known in the art. Heatexchangers can be included to reheat the final conditioned gas to therequired temperature or relative humidity for the desired downstreamapplication. A compressor can also optionally be included to compressthe final conditioned gas to the required pressures for the desireddownstream application.

In one embodiment in which the GCS is integrated with a plasmagasification system, evaporative cooling towers (dry quench) may be usedto cool the syngas that enters the GCS from the gasification system. Inone embodiment, the GCS incorporates an evaporative cooling tower inStage One to cool the temperature of the syngas from about 1000° C. toabout 150-200° C., for example, by adiabatic saturation, which involvesdirect injection of water into the gas stream in a controlled manner.The evaporating cooling process is a dry quench process, and can bemonitored to ensure that the cooled gas is not wet, i.e. that therelative humidity of the cooled gas is still below 100% at the cooledtemperature. In one embodiment of the invention, the GCS comprises anevaporative cooling tower or dry quench in Stage One that cools thesyngas fed into the GCS from a temperature of about 740° C. to about150-200° C.

In one embodiment, a gas cooler may be included in Stage Two of the GCS.The gas cooler (water cooled) functions to cool input gas that ispressurized through a gas moving unit (see below) and concomitantlyheated. In one embodiment, the gas cooler cools the gas to about 35° C.

In one embodiment, the GCS comprises a humidity controller. The humiditycontroller functions to ensure that the humidity of the output gas isappropriate for the downstream application desired. For example, ahumidity controller may include a chiller to cool the gas stream andthus condense some water out of the gas stream. This water can beremoved by a gas/liquid separator. In one embodiment, the GCS comprisesa humidity controller for treatment of the conditioned gas to provide ahumidity of about 80% at 26° C. In one embodiment, the GCS is configuredto first cool the conditioned gas to approximately 26° C. and thenreheat the gas to 40° C. The conditioned gas may then be stored.

Gas Moving Units

In one embodiment, the GCS includes one or more gas moving units whichsupply a driving force for the gas throughout the GCS. In one embodimentin which the GCS is integrated with a plasma gasification system, theGCS comprises a gas moving unit capable of moving the input gas from theexit of the gasification system up to exit of the GCS.

Suitable gas moving units are known in the art and include, for example,process gas blowers, pressure blowers, vacuum pumps, positivedisplacement rotary blowers, reciprocating compressors, and rotary screwcompressors and the like. As is also known in the art, the selection ofthe gas moving unit(s) to be used can be based on, for example, thelocation of the unit(s) in the system, the temperature of the input gasmoving through the gas moving unit, and/or whether the presence of thegas moving unit will affect the operation of the proximal components ofthe system, for example, due to backpressure or suction.

Pressure blowers are similar to centrifugal pumps but are, however,designed for gas applications. The blades of the blower spin, therebysucking air into the middle of the blower and expelling air in theradial direction at a higher pressure. The blowers can be designed forhigh pressure where the blades of the blower reach the outer casing toallow for positive displacement of the air in order to reach a highincrease in pressure across the device.

Vacuum pumps are designed similarly to blowers but operate where theupstream pressure is a vacuum and the gas would not flow in the regularblower's direction. Therefore the vacuum pump is designed to capture alarge volume of space (which is gas under vacuum, so small amount ofactual gas) and compress that space between its scrolls to a higherpressure as the inner scroll rotate. The vacuum pump can only run invacuum atmospheres (to a slight positive pressure) due to high pressureincrease across the pump (high power consumption), and strain on scrollsat higher pressures.

Positive displacement rotary blowers operate as follows. As the dual,FIG. 8 shaped impellers of the blower rotate, a fixed quantity of gas(or air) at the inlet is trapped between the impeller and the casingparts. With each revolution, four of these “pockets” of gas are trapped,then forced out the discharge against whatever pressure exists in thesystem. When each of these pockets is expelled, a pulse is generated,which imposes a certain shock load on the blower and the downstreamsystem. This allows the gas in the pocket to pressurize slowly todischarge conditions via the internal “jets,” which in turnsignificantly reduces pulsations and shock load on the equipment.

Reciprocating compressors are positive displacement machines, meaningthat they increase the pressure of the air by reducing its volume. Therelationship between pressure and volume is known in the art.Reciprocating compressors comprise a crankshaft, connecting rods, andpistons. Single-stage and two-stage reciprocating compressors arecommercially available. Single-stage compressors are generally used forpressures in the range of 70 psig to 100 psig. Two-stage compressors aregenerally used for higher pressures in the range of 100 psig to 250psig.

Rotary screw compressors operate as follows. As the screws rotate theintake air is compressed in the reducing void between the rotor lobesand the airend casing, until the final pressure is reached and the airis discharged.

In one embodiment, the GCS comprises a process gas blower as a gasmoving unit. In one embodiment, the GCS comprises a gas moving unit thatadditionally pressurizes the gas passing through the blower.

The optimal placement of the gas moving unit within the GCS can bedetermined by one of skill in the art. In one embodiment, the gas movingunit is located so as to increase the efficiency of one or more of theprocessing steps of the GCS. For example, in one embodiment, the gasmoving unit is located upstream of a heavy metal polisher such as amercury polisher to optimise mercury removal, as this occurs mostefficiently under pressure, and can also allow a reduced size mercurypolisher vessel to be used. In an embodiment where the GCS is integratedwith a plasma gasification converter, the gas moving means isincorporated into the GCS downstream of a gas cooler. In one embodiment,the gas moving unit is located within the GCS upstream of a gas cooler.

Management of Waste Products

The GCS may optionally include components for the processing of wasteproducts, if necessary. Alternatively, waste products produced by theGCS can be collected and processed, as necessary, externally to the GCS.

For example, any hydrochloric acid recovered from the acid gasseparation steps may have a marketable value. If the amount of chlorineis of economically significant size, the chlorine may be reclaimed usingart-known techniques. In one embodiment in which the GCS produces asufficient amount of sulphur compound to justify the cost, a sulphurrecovery system is positioned along the path of the GCS at a locationwhere a temperature is reached where the sulphur compounds becomestable. The type and size of the sulphur recovery system depends on theexpected amount of sulphur in the input gas. Suitable sulphur recoverysystems are known in the art. For example, for input gas that contains ahigh amount of sulphur, a second-stage liquid washing process can beused to remove sulphur compounds from the gas. An amine scrubber can beused to remove hydrogen sulphide and carbon dioxide from the input gasstream leaving a gas stream mainly comprising hydrogen, carbon monoxideand an inert gas. If the anticipated amount of sulphur is fairly low, aswould be expected for input gas generated from low sulphur grades ofcoal, an iron filing technique may be used to react sulphur withelemental iron to produce iron sulphide. This may be accomplished bycirculating iron pellets between a compartment in the conduit and arecovery compartment.

The present invention further contemplates that sulphur recovered fromthe input gas can be recovered and disposed of. For example, if thesulphur comprises limited heavy metal with biomass, it can be useful foragricultural land spreading. If the sulphur has considerable heavymetal, it can be converted to sulphate, processed for removal of theheavy metals and disposed of as sulphate salts in liquid waste form, orwaste water. If government environmental regulations require additionaltreatment of the sulphur due to contact with Thiobacillus bacteria, theprocessed sulphur can be sterilized before disposal. Alternative meansof sterilizing include the addition of disinfectants such as bleach ortreatment with UV radiation.

In one embodiment of the present invention, the GCS is configured suchthat the waste water generated by the GCS comprises only salts andlittle elemental sulphur and biomass, which can be disposed of to thewaste water sewer. If required by governmental regulations, the wastewater can be sterilized using heat and residence time, prior todischarge to the sewer.

In one embodiment as shown in FIG. 10, the particulate matter and heavymetals (solids) from Stage One of the GCS are directed to the solidresidue conditioner 1065 where they are melted. The solids melted in thesolid residue conditioner can be used for road aggregate and buildingmaterial applications; or they can be vitrified i.e. mixed with silicaand encapsulated in glass for disposal. Procedures for carrying outthese operations are known in the art. In some embodiments, dependingupon plant considerations and local regulations, solids from the gasclean-up system may be sent off-site for safe disposal.

Design of the GCS Processing Steps Parallel Processes

As described above, in one embodiment, the GCS carries out processingsteps in parallel. In this embodiment, the GCS comprises a converter GC,a solid residue conditioner and a solid residue GC. Each of theConverter GC and Solid residue GC carries out Stage One and Stage Twoprocesses in parallel. The solid residue conditioner receives solidresidue from the Converter GC Stage One processes and optionally fromthe converter that is providing the input gas for the GCS. The solidresidue conditioner melts the solid residue and produces a secondary gasstream, which is processed through the solid residue GC.

Converging Processes

In one embodiment, the GCS comprises a converter GC, a solid residueconditioner and a solid residue GC, and the converter GC and the solidresidue GC carry out converging process steps as follows. The solidresidue conditioner receives solid residue from the Converter GC StageOne processes and optionally from the converter that is providing theinput gas for the GCS. The solid residue conditioner melts the solidresidue and produces a secondary gas stream, which is processed throughStage One by the solid residue GC. The partially conditioned gas fromthe solid residue GC can then be processed either through the furtherprocessing steps (Stage Two) of the converter GC or through both the dryphase separation steps (Stage One) and the further processing steps(Stage Two) of the converter GC.

In one embodiment, as depicted in FIG. 2, the converter gas conditioner4 receives input gas from a low temperature gasifier (or “converter”)50, and heavy metal and particulate matter that is separated from theinput gas in Stage One is diverted to the solid residue conditioner 265,where it is converted to a secondary gas stream. This secondary gasstream is processed through Stage One dry phase separation steps in thesolid residue GC 5, and is then fed into the converter GC 4 prior to theStage One. In one embodiment, the secondary gas stream is processedthrough Stage One dry phase separation steps in the solid residue GC 5,and is then fed into the converter GC 4 after Stage One dry phaseseparation steps, and the secondary gas stream is processed in Stage Twofurther processing steps of the converter GC 4.

Linear Processes

In one embodiment, the GCS carries out a linear processing sequence inwhich a low temperature gasifier generates an input syngas which isprocessed through Stage One and Stage Two processes. The input gas isgenerated in the low temperature gasifier. In this embodiment, the oneor more dry/solid stage separation steps (Stage One) are carried out,followed by the one or more further processing steps (Stage Two). Forexample, with reference to FIG. 3, the following processing steps arecarried out by the GCS 6 after input gas from a converter 51 comprisinglow temperature gasifier is cooled in a heat exchanger 310: 1)particulate matter is removed in a cyclone filter 330 (Stage One dryphase separation); 2) acid gases (HCl) are then separated from the inputgas using a chlorite guard bed 340; 3) H₂S is removed from the input gasusing sorbent 360, and 4) a final step to separate particulate matterusing a ceramic filter 362 is carried out. As an optional step, theoutput gas is then stored in a storage tank.

Control of the Process

In one embodiment of the invention, a control system may be provided tocontrol one or more processes implemented in, and/or by, the varioussystems and/or subsystems disclosed herein, and/or provide control ofone or more process devices contemplated herein for affecting suchprocesses. In general, the control system may operatively controlvarious local and/or regional processes related to a given system,subsystem or component thereof, and/or related to one or more globalprocesses implemented within a system, such as a gasification system,within or in cooperation with which the various embodiments of theinvention may be operated, and thereby adjusts various controlparameters thereof adapted to affect these processes for a definedresult. Various sensing elements and response elements may therefore bedistributed throughout the controlled system(s), or in relation to oneor more components thereof, and used to acquire various process,reactant and/or product characteristics, compare these characteristicsto suitable ranges of such characteristics conducive to achieving thedesired result, and respond by implementing changes in one or more ofthe ongoing processes via one or more controllable process devices.

The control system generally comprises, for example, one or more sensingelements for sensing one or more characteristics related to thesystem(s), process(es) implemented therein, input(s) provided therefor,and/or output(s) generated thereby. One or more computing platforms arecommunicatively linked to these sensing elements for accessing acharacteristic value representative of the sensed characteristic(s), andconfigured to compare the characteristic value(s) with a predeterminedrange of such values defined to characterise these characteristics assuitable for selected operational and/or downstream results, and computeone or more process control parameters conducive to maintaining thecharacteristic value with this predetermined range. A plurality ofresponse elements may thus be operatively linked to one or more processdevices operable to affect the system, process, input and/or output andthereby adjust the sensed characteristic, and communicatively linked tothe computing platform(s) for accessing the computed process controlparameter(s) and operating the process device(s) in accordancetherewith.

In one embodiment, the control system provides a feedback, feedforwardand/or predictive control of various systems, processes, inputs and/oroutputs related to the conversion of carbonaceous feedstock into a gas,so to promote an efficiency of one or more processes implemented inrelation thereto. For instance, various process characteristics may beevaluated and controllably adjusted to influence these processes, whichmay include, but are not limited to, the heating value and/orcomposition of the feedstock, the characteristics of the product gas(e.g. heating value, temperature, pressure, flow, composition, carboncontent, etc.), the degree of variation allowed for suchcharacteristics, and the cost of the inputs versus the value of theoutputs. Continuous and/or real-time adjustments to various controlparameters, which may include, but are not limited to, heat sourcepower, additive feed rate(s) (e.g. oxygen, oxidants, steam, etc.),feedstock feed rate(s) (e.g. one or more distinct and/or mixed feeds),gas and/or system pressure/flow regulators (e.g. blowers, relief and/orcontrol valves, flares, etc.), and the like, can be executed in a mannerwhereby one or more process-related characteristics are assessed andoptimized according to design and/or downstream specifications.

Alternatively, or in addition thereto, the control system may beconfigured to monitor operation of the various components of a givensystem for assuring proper operation, and optionally, for ensuring thatthe process(es) implemented thereby are within regulatory standards,when such standards apply.

In accordance with one embodiment, the control system may further beused in monitoring and controlling the total energetic impact of a givensystem. For instance, a a given system may be operated such that anenergetic impact thereof is reduced, or again minimized, for example, byoptimising one or more of the processes implemented thereby, or again byincreasing the recuperation of energy (e.g. waste heat) generated bythese processes. Alternatively, or in addition thereto, the controlsystem may be configured to adjust a composition and/or othercharacteristics (e.g. temperature, pressure, flow, etc.) of a productgas generated via the controlled process(es) such that suchcharacteristics are not only suitable for downstream use, but alsosubstantially optimised for efficient and/or optimal use. For example,in an embodiment where the product gas is used for driving a gas engineof a given type for the production of electricity, the characteristicsof the product gas may be adjusted such that these characteristics arebest matched to optimal input characteristics for such engines.

In one embodiment, the control system may be configured to adjust agiven process such that limitations or performance guidelines withregards to reactant and/or product residence times in variouscomponents, or with respect to various processes of the overall processare met and/or optimised for. For example, an upstream process rate maybe controlled so to substantially match one or more subsequentdownstream processes.

In addition, the control system may, in various embodiments, be adaptedfor the sequential and/or simultaneous control of various aspects of agiven process in a continuous and/or real time manner.

In general, the control system may comprise any type of control systemarchitecture suitable for the application at hand. For example, thecontrol system may comprise a substantially centralized control system,a distributed control system, or a combination thereof. A centralizedcontrol system will generally comprise a central controller configuredto communicate with various local and/or remote sensing devices andresponse elements configured to respectively sense variouscharacteristics relevant to the controlled process, and respond theretovia one or more controllable process devices adapted to directly orindirectly affect the controlled process. Using a centralizedarchitecture, most computations are implemented centrally via acentralized processor or processors, such that most of the necessaryhardware and/or software for implementing control of the process islocated in a same location.

A distributed control system will generally comprise two or moredistributed controllers which may each communicate with respectivesensing and response elements for monitoring local and/or regionalcharacteristics, and respond thereto via local and/or regional processdevices configured to affect a local process or sub-process.Communication may also take place between distributed controllers viavarious network configurations, wherein a characteristics sensed via afirst controller may be communicated to a second controller for responsethereat, wherein such distal response may have an impact on thecharacteristic sensed at the first location. For example, acharacteristic of a downstream product gas may be sensed by a downstreammonitoring device, and adjusted by adjusting a control parameterassociated with the converter that is controlled by an upstreamcontroller. In a distributed architecture, control hardware and/orsoftware is also distributed between controllers, wherein a same butmodularly configured control scheme may be implemented on eachcontroller, or various cooperative modular control schemes may beimplemented on respective controllers.

Alternatively, the control system may be subdivided into separate yetcommunicatively linked local, regional and/or global control subsystems.Such an architecture could allow a given process, or series ofinterrelated processes to take place and be controlled locally withminimal interaction with other local control subsystems. A global mastercontrol system could then communicate with each respective local controlsubsystems to direct necessary adjustments to local processes for aglobal result.

The control system of the invention may use any of the abovearchitectures, or any other architecture commonly known in the art,which are considered to be within the general scope and nature of thepresent disclosure. For instance, processes controlled and implementedwithin the context of the invention may be controlled in a dedicatedlocal environment, with optional external communication to any centraland/or remote control system used for related upstream or downstreamprocesses, when applicable. Alternatively, the control system maycomprise a sub-component of a regional an/or global control systemdesigned to cooperatively control a regional and/or global process. Forinstance, a modular control system may be designed such that controlmodules interactively control various sub-components of a system, whileproviding for inter-modular communications as needed for regional and/orglobal control.

The control system generally comprises one or more central, networkedand/or distributed processors, one or more inputs for receiving currentsensed characteristics from the various sensing elements, and one ormore outputs for communicating new or updated control parameters to thevarious response elements. The one or more computing platforms of thecontrol system may also comprise one or more local and/or remotecomputer readable media (e.g. ROM, RAM, removable media, local and/ornetwork access media, etc.) for storing therein various predeterminedand/or readjusted control parameters, set or preferred system andprocess characteristic operating ranges, system monitoring and controlsoftware, operational data, and the like. Optionally, the computingplatforms may also have access, either directly or via various datastorage devices, to process simulation data and/or system parameteroptimization and modeling means. Also, the computing platforms may beequipped with one or more optional graphical user interfaces and inputperipherals for providing managerial access to the control system(system upgrades, maintenance, modification, adaptation to new systemmodules and/or equipment, etc.), as well as various optional outputperipherals for communicating data and information with external sources(e.g. modem, network connection, printer, etc.).

The processing system and any one of the sub-processing systems cancomprise exclusively hardware or any combination of hardware andsoftware. Any of the sub-processing systems can comprise any combinationof none or more proportional (P), integral (I) or differential (D)controllers, for example, a P-controller, an I-controller, aPI-controller, a PD controller, a PID controller etc. It will beapparent to a person skilled in the art that the ideal choice ofcombinations of P, I, and D controllers depends on the dynamics anddelay time of the part of the reaction process of the gasificationsystem and the range of operating conditions that the combination isintended to control, and the dynamics and delay time of the combinationcontroller. It will be apparent to a person skilled in the art thatthese combinations can be implemented in an analog hardwired form whichcan continuously monitor, via sensing elements, the value of acharacteristic and compare it with a specified value to influence arespective control element to make an adequate adjustment, via responseelements, to reduce the difference between the observed and thespecified value. It will further be apparent to a person skilled in theart that the combinations can be implemented in a mixed digital hardwaresoftware environment. Relevant effects of the additionally discretionarysampling, data acquisition, and digital processing are well known to aperson skilled in the art. P, I, D combination control can beimplemented in feed forward and feedback control schemes.

In corrective, or feedback, control the value of a control parameter orcontrol variable, monitored via an appropriate sensing element, iscompared to a specified value or range. A control signal is determinedbased on the deviation between the two values and provided to a controlelement in order to reduce the deviation. It will be appreciated that aconventional feedback or responsive control system may further beadapted to comprise an adaptive and/or predictive component, whereinresponse to a given condition may be tailored in accordance with modeledand/or previously monitored reactions to provide a reactive response toa sensed characteristic while limiting potential overshoots incompensatory action. For instance, acquired and/or historical dataprovided for a given system configuration may be used cooperatively toadjust a response to a system and/or process characteristic being sensedto be within a given range from an optimal value for which previousresponses have been monitored and adjusted to provide a desired result.Such adaptive and/or predictive control schemes are well known in theart, and as such, are not considered to depart from the general scopeand nature of the present disclosure.

The GCS according to the invention comprises a control system formaintaining a set point for reaction conditions within a specified rangeof variability during the processing of an input syngas to a conditionedgas which has a desired chemical and physical composition. This controlsystem is automatable and can be configured to be applicable to avariety of gas conditioning systems.

In one embodiment, if the control system senses a decrease in efficiencyor alternate functional deficiency in a process of the GCS, which isoutside a desired operational range, the control system can beconfigured to enable the diversion of the gas stream to a backupprocess, a flare stack, a combustion chamber or a backup GCS. Howeverand as is known in the art, if for example the level of HCl and/or H₂Sin the gas stream is above allowable emission limits, the gas stream isnot diverted to a flare stack and thus may be diverted to a backupprocess which can modify the level of HCl and/or H₂S.

The control system of this invention comprises: a Process MonitoringSubsystem and a Process Controlling Subsystem. The Process MonitoringSubsystem includes one or more sensing elements which are configured toanalyze one or more of the chemical composition of the gas streamthrough the GCS, the gas flow rate, pressure, thermal parameters and thelike. The Process Control Subsystem comprises one or more responseelements, the action of which is in response to a process characteristicsensed by the sensing elements of the Process Monitoring Subsystem, aswell as other information monitoring elements which are configured as anintegrated Process Control Subsystem.

In one embodiment, the control system may provide a means forfine-tuning the processing steps of the GCS and thus may provide a meansfor substantially minimizing drift from desired optimal conditions forprocessing of the input gas. By having a single integrated controlsystem that is controlled by a real time application running on acomputer processor which is capable of monitoring the operationalcomponents of the GCS and process steps and modifying them if required,the control system can ensure the substantially optimum and continuousgeneration of a conditioned gas in a safe manner and can ensuresubstantially efficient and self sustaining operation of the GCS.

The Process Control Subsystem includes response elements for adjustingthe conditions within the GCS to optimize the efficiency of processinginput gas and the resulting characteristics of the conditioned gas, forexample the composition thereof. Ongoing adjustments to the reactants(for example, activated carbon injection, pH control for the HClscrubber, reactants required for H₂S system optimization) can beexecuted in a manner which enables this process to be conductedefficiently and optimized according to design specifications. Somefactors influencing the efficiency of the GCS are the air flow rate(redox), caustic addition rate (pH), conductivity (bleed) into thebioreactor of the H₂S removal system, and the pressure in the mercurypolisher (heavy metal removal system). The Process Monitoring Subsystemincludes one or more sensing elements for measuring parametersincluding, for example, the temperature, pressure, flow-rate,composition and the like, of the gas at various points within the GCS.The sensing elements can measure these parameters in real time and usethe data collected to determine if, for example, the operation of theGCS requires modification. For example, a sensing element can detect aparticular condition which may result in a requirement for moreactivated carbon to be injected into the GCS, or that the pH of the HClscrubber needs to be adjusted, or that the air flow into the bioreactorof the H₂S removal system needs to be adjusted, or that the pH orconductivity of the H₂S removal system needs to be adjusted. Theserequired adjustments as determined by the Process Monitoring Subsystembased on the sensed information, can be enabled by the Process ControlSubsystem.

In one embodiment of the invention, the Process Monitoring Subsystemincorporates a sensing means configured to monitor the conditioned gasoutput and based on predetermined parameters or conditioned gasobjectives, this facilitates the operating conditions within the GCS tobe closely controlled by the response elements of the Process ControlSubsystem thereby achieving a suitable conditioned gas composition whichcan meet the gas input requirements of one or more downstreamapplications in terms of energy requirements, temperature, pressure orother conditioned gas requirements.

Control Elements

Sensing elements contemplated within the present context, as defined anddescribed above, can include, but are not limited to sensors, detectors,analyzers, thermocouples, pressure transducers, chemical analyzers orthe like, wherein a worker skilled in the art would readily understandthe format of a sensing element which can collect information relatingto a specific characteristic.

Response elements contemplated within the present context, as definedand described above, can include, but are not limited to, variouscontrol elements operatively coupled to process-related devicesconfigured to affect a given process by adjustment of a given controlparameter related thereto. For instance, process devices operable withinthe present context via one or more response elements, may include, butare not limited to particular matter is monitored to determine if afiltering system is to be activated; gas temperature is monitored atinput of GCS to adjust flow of process air therethrough; pressure ismonitored within GVS to adjust downstream blower in order to maintaindesired pressure.

Gas Composition Monitoring

Sensing elements that can be used to measure the composition of the gasflow through the GCS are known in the art and include, for example, gasmonitors, in situ gas analyzers, in situ probe gas analyzers, extractivegas analyzers, and the like. These sensing elements are used todetermine the amount of components such as hydrogen, carbon monoxide,oxygen, H₂S, carbon dioxide or the like, which are present in the inputgas, conditioned gas or a gas at an intermediate state between inputcomposition and conditioned composition.

As is known in the art, the amount of particulate matter that is presentin the input gas can vary depending on the source of the input gas. Forexample, as is known in the art of plasma gasification processing, theamount of particulate matter in a gas stream exiting a gasifier can havea direct relationship on the amount of particular matter or otherpollutants in the gas stream. For example, pollutants tend to adhere toparticulate matter, which assists their exit from the reactor vessel andthrough the exhaust piping. Therefore substantially minimizing theamount of particulate matter in the input gas stream may also minimizethe emission rate of pollutants. In one embodiment of the invention,changes in the amount of particulate matter in the gas stream can bedetermined by monitoring the opacity of the gas stream and establish abaseline for an acceptable level which can be based on particular matterconcentration in accordance with regulatory authority restrictionswithin the location of processing.

Thus, in one embodiment of the invention, the amount of particulatematter in the gas at various locations within the GCS is monitored usingone or more opacity monitors installed within the gas transfer devicesor piping within the GCS to provide real-time feedback of opacity of thegas, thereby providing an optional mechanism for automation of theadjustment of the filtering process. For example, the adjustment of theamount of activated carbon that is injected into the input gas stream inorder to maintain the level of particulate matter below the maximumallowable concentration.

In one embodiment and in order to substantially optimize the operationof the opacity monitors, it is desirable to maintain sensor elementswhich are free of deposits therein to ensure accuracy of readings. Theprevention of deposition on the sensor elements can be achieved by forexample the provision of a small amount of nitrogen across the face ofeach sensing element to prevent airborne particles from settling; themaintenance of a slightly negative pressure in this portion of the gashandling system to ensure airborne particles are drawn past the sensorelements or other method as would be readily understood. In oneembodiment, nitrogen is used unless the use thereof will be detrimentalto the chemical composition of the conditioned gas required for adownstream application. As would be know to a worker skilled in the art,other examples of gases that can be used to mitigate the deposition ofparticular matter on the one or more sensing elements can include argon,CO₂, or other gas as would be readily understood.

Temperature Monitoring

In one embodiment of the invention, there is provided one or moresensing elements configured to monitor the temperature at one or moresites located throughout the GCS, wherein such data can be acquired on aperiodic, intermittent or continuous basis. As is known in the art, asensing element capable of monitoring the temperature of the gas flowingthrough the GCS include thermocouples, optical thermometers and pressuregauges. In one embodiment of the invention, the sensing elements formonitoring the temperature are thermocouples installed at locations inthe GCS as required. In one embodiment, the sensing elements formonitoring the temperature are optical thermometers. Suitable opticalthermometers are known in the art, wherein a non-limiting example of anoptical thermometer is a thermowell. In one embodiment a plurality ofthermocouples and pressure gauges can be used to monitor the temperatureat critical points throughout the GCS.

Sensing elements for monitoring the temperature of the gas stream may belocated throughout the GCS, and for example, at a location prior toentry of the syngas into the GCS, exit of the conditioned from the GCSas well as at various locations throughout the GCS.

Pressure Monitoring

In one embodiment of the invention, there is provided sensing elementsfor monitoring the pressure within the GCS, wherein such data areacquired on a continuous, intermittent, periodic or real-time basis. Inone embodiment, the sensing elements for monitoring the pressurecomprise pressure sensors such as pressure transducers, and/or pressuregauges located throughout the GCS.

Suitable locations for pressure sensors are, for example, at the exitpoint of the recuperator prior to entry of the input gas into the GCS,at the outlet blower, or at locations where the pressure can be measuredacross a particle removal unit such as a baghouse, or a carbon filterbed. In one embodiment, the sensing elements for monitoring the pressureare located across an acid gas removal system such as an HCl scrubber,or an H₂S scrubber. Sensing elements for monitoring the pressure canalso be located in the solid residue conditioner.

In one embodiment, sensing elements for monitoring pressure are locatedon the vertical wall of a converter that is integrated with the GCS. Theefficiency of certain processes within the GCS can depend upon thepressure in the GCS. For example, the efficiency of a mercury polisheris improved when the GCS is under pressure rather than a vacuum. Datarelating to the pressure of the system is used by the feedback controlsystem to determine, for example on a real time basis, whetheradjustments to pressure dependent processes such as the heavy metalpolisher are required.

In one embodiment, a continuous readout of differential pressuresthroughout the complete system is provided. In this manner, the pressuredrop across each individual processing component of the GCS can bemonitored to substantially rapidly pinpoint developing or actualproblems in the GCS during processing of the input gas stream.

Flow Rate Monitoring

In one embodiment of the invention, there are provided sensing elementsto monitor the rate of gas flow rate at sites located throughout theGCS, wherein such data is acquired on a continuous, intermittent orperiodic basis. A sensing element to monitor the rate of gas flowinclude gas flow meters or the like. In one embodiment, the rate of gasflow is monitored using one sensing element. In another embodiment, whena duplicate system is provided as a backup GCS, a second sensing elementto monitor the rate of gas flow is provided in the backup GCS.

For example, syngas production can be uneven due to the non-homogeneousnature of the feedstock and possible upsets such as failure of supportequipment such as the process air blower, torch water leak, controlvalves, waste feed rate, and/or baghouse backpulse. These changes can bemonitored by observing the temperatures and pressure in the GCS as wellas gas flow and composition among others. A resulting fluctuation can becorrected by proper control of the syngas blower, control valves, wastefeed rate, and/or baghouse backpulse, the amount of air going to eachstage, and varying the rates (and ratio) of MSW and HCF addition, forexample.

Gas Moving Units

The control system can also integrate with the gas moving units. The gasmoving units can be controlled by adjusting the speed at which it movesthe input gas through the GCS. In one embodiment, where the GCS isintegrated with a low temperature gasifier system to produce energy tooperate internal combustion engines, the speed at which the gas movingunit moved gas is controlled in order to control the pressure in theconverter.

Optional Manual Controls

The GCS can optionally comprise manual sampling and or control systemsas a back up for the automated control system. For example, the inputgas stream within the GCS can be sampled and analyzed by gaschromatography (GC) to determine chemical composition of the input gasstream. In one embodiment, sample locations for these analyses arespread throughout the GCS. In one embodiment, the input gas stream issampled at a location between Stage One and Stage Two processes, andmore specifically between the step in which particulate matter and heavymetals are removed and the removal of HCl. In another embodiment, thesyngas stream is sampled immediately after the syngas stream exits theHCl scrubber in Stage Two. In still another embodiment, the syngas issampled immediately after it exits the H₂S scrubber.

In an alternate manual control step, the heavy metal or mercury contentin feedstock can be measured, and the appropriate amount of carboninjected into the GCS can be pre-set depending on the heavy metalcontent of the feedstock.

The concentration of H₂S exiting the H₂S scrubber can also be measuredand controlled manually as is known in the art. For example, theconcentration of H₂S exiting the H₂S scrubber can be altered byadjusting the appropriate parameters for the H₂S scrubber.Alternatively, the concentration of H₂S exiting the scrubber can bealtered by lowering the amount of sulphur fed into the system by, forexample, decreasing the tire content in the HCF in the feedstock.

One of skill in the art will understand that additional sensing andresponse elements can be included in the control system as appropriate.

Incorporation of the GCS into a Gasification Facility

In one embodiment, the GCS is integrated with a gasification system. Aschematic diagram of a GCS incorporated into a gasification facility inone embodiment of the invention is shown schematically in FIG. 10. Theproduct gas produced from such gasification systems or converters can beprocessed through a GCS in order to provide an output syngas having adesired set of characteristics. As noted above, the desired set ofcharacteristics depends on the desired downstream application in whichthe output syngas is to be used. The syngas product produced from thegasification converter is transferred to the GCS via one or more gastransfer means.

Gas transfer means are known in the art and suitable gas transfer meanscan be readily identified by one of skill in the art. Non-limitingexamples of suitable gas transfer means include pipes, ducts andconduits. In one embodiment, where the GCS is integrated with a plasmagasification converter, vacuum extraction using an induction fan is usedto continuously withdraw hot syngas product from the plasma gasificationconverter through an exit gas outlet(s) of the plasma gasificationconverter.

The control system for the GCS can function independently of thefacility control system to manage processing of the gas through the GCS.Alternatively, the control system for the GCS can be incorporated intothe control system for the entire facility.

Downstream Applications for Output Gas

The conditioned gas produced by the GCS can be used in downstreamapplications.

Examples of such downstream applications include, but are not limitedto, internal combustion engines, fuel cell technologies, combustionturbine engines, polygeneration of electricity and synthetic fuels, andchemical synthesis. The conditioned gas produced by the GCS of thepresent invention may also be used in the plastics and fertilizerindustries.

Selected technologies are described below.

Combustion Turbine Engines

A combustion turbine engine combines air (O₂ with CO and the H₂ togenerate CO₂, H₂O and energy. The energy is in the form of heat andpressure. As the gas expands during the combustion process, it expandsacross a multiple stage power turbine to drive for the axial flow aircompressor and the generator to make electricity. The fuel gas must bepressurized in order to feed the gas turbine as the combustion takesplace at a pressure approximately equivalent to the compression ratio ofthe combustion turbine.

If the syngas is to be delivered to one or more combustion turbineengines, the syngas would either be compressed prior to delivery to theengine or the entire gasification process is operated under a pressuresufficient for delivery. In one embodiment, the pressure would rangefrom 100-600 psig depending of the compression ratio of the particularengine. In one embodiment, the pressure would range from 20 to 80 bars.In one embodiment, the pressure is 36 bars.

Before entering the gas turbine fuel system, the pressurized, dryproduct gas may be further filtered to collect any trace quantities ofparticulate matter that may have been picked up in the processingequipment and piping.

A pre-heating system can be employed to pre-heat the cooled andcompressed fuel gas if desired. In one embodiment, the pre-heating stepresults in a temperature increase that is sufficient to decrease therelative humidity of the gas to at or below 80%. In one embodiment, thepre-heating step results in a temperature increase that is sufficient todecrease the condensation of moisture when passing through thecombustion turbine engine. A pre-heating system can be configured to usewaste heat from a gas cooling system located somewhere else in thesystem, either upstream when the gas is cooled after leaving thegasification process, or downstream, such as recovered from theturbines. Pre-heating may be useful where the gas cooling system coolsthe fuel gas to a temperature required by a scrubber, and thattemperature is below a desirable temperature for the cleaned fuel gasthat is to be introduced into combustion chamber. Steam injection canalso be used on some combustion turbines to control NOx formation, andconstitutes an alternate to dry emission technology.

An Internal Combustion Engine

Energy can be produced using a process similar to that discussed aboveexcept that the compressor, combustor and gas turbine are replaced by aninternal combustion engine. An internal combustion engine may be easierto utilize and may be more cost efficient than a compressor-gas turbine,especially for small-scale gasification electroconversion units. Air andauxiliary fuel may be fed to the internal combustion engine in apredetermined manner based on the composition of fuel gas.

Environmentally attractive low emission internal combustionengine-generator systems for gasification systems can be provided togreatly improve efficiency and pollution reduction. Spark ignitioninternal combustion engines are advantageous in that such engines areless expensive for very small units and are easier to start and stopthan turbines. To facilitate production of a desired level of electricalpower, particularly during startup, an auxiliary power such ashydrogen-rich gas, propane, natural gas or diesel fuel may be used topower the internal combustion engine. The amount of auxiliary fuel mayvary depending on the heating value of the carbonaceous feedstock beinggasified and the power requirements for the overall gasification system.

The use of internal combustion engines to generate electricity,particularly in the context of distributed electric power generatingsystems, represents an already mature technology. Although dieselengines have captured the majority of this market, other types ofinternal combustion engines can be readily adapted to run on the syngasproduced by this system.

Output syngas from the GCS suitable for use in internal combustionengines contains limited concentrations of HCl and H₂S. In oneembodiment, output syngas comprises less than 10 ppm HCl. In oneembodiment, output syngas comprises less than 7 ppm HCl. In oneembodiment, output syngas comprises less than 5 ppm HCl. In oneembodiment, output syngas comprises less than 3 ppm HCl. In oneembodiment, output syngas comprises less than 30 ppm H₂S. In oneembodiment, output syngas comprises less than 25 ppm H₂S. In oneembodiment, output syngas comprises less than 20 ppm H₂S. In oneembodiment, output syngas comprises less than 10 ppm H₂S.

Fuel Cell Technologies

The syngas from plasma converter can be fed into a high temperature fuelcell (either SOFC or MCFC), after removing contaminants, such as PM, HCLand H2S, at relatively high temperatures (SOFC, 1000° C.; MCFC 650° C.).More stringent contaminant limits have to be met in order to prevent thedegradation of fuel cell performance. The GCS configuration is requiredto vary to fit the fuel cell operation conditions. The syngas andoxidant compositions also need to be adjusted to optimize the efficiencyor output of a high temperature fuel cell.

Molten carbonate fuel cells (MCFC) contain an electrolyte that is acombination of alkali (Li, Na, and K) carbonates stabilized in a LiAlO₂ceramic matrix. The gaseous input fuel mixture can include carbonmonoxide, hydrogen, methane, and hydrocarbons, with limits on totalhydrocarbons, particulate loading, sulphur (in the form of H₂S),ammonia, and halogens (e.g., HCl). At the operating temperature of about1200° F. (650° C.), the salt mixture is liquid and a good ionicconductor.

The anode process for an MCFC involves a reaction between hydrogen andcarbonate ions (CO₃ ⁻) from the electrolyte, which produces water andcarbon dioxide (CO₂), while releasing electrons to the anode. Thecathode process combines oxygen and CO₂ from the oxidant stream withelectrons from the cathode to produce carbonate ions, which enter theelectrolyte. If the CO₂ content in the fuel gas is insufficient, CO₂ canbe recycled from the emission stream. An MCFC produces excess heat at atemperature, which is sufficiently high to be usable in producing highpressure steam that may be fed to a turbine to generate additionalelectricity. In combined cycle operation (steam turbine poweredgeneration and fuel cell power generation), electrical efficiencies inexcess of 60% are predicted for mature MCFC systems.

A solid oxide fuel cell (SOFC) uses a hard ceramic electrolyte insteadof a liquid and operates at temperatures up to 1,000° C. (about 1,800°F.). In this type of fuel cell, a mixture of zirconium oxide and calciumoxide forms a crystal lattice, although other oxide combinations havealso been used as electrolytes. The solid electrolyte is coated on bothsides with specialized porous electrode materials. At a relatively highoperating temperature, oxygen ions (with a negative charge) migratethrough the crystal lattice.

The fuel gas containing hydrogen and carbon monoxide is passed over theanode while a flow of negatively charged oxygen ions moves across theelectrolyte to oxidize the fuel. The oxygen is supplied, usually fromair, at the cathode. Electrons generated at the anode travel through anexternal load to the cathode, completing the circuit that carries theelectrical current.

Generating efficiencies can range up to about 60 percent. Like moltencarbonate fuel cells, solid oxide cells require high operatingtemperatures that provide the opportunity for “co-generation”—i.e., acombined heat and power application using waste heat to generate steamfor space heating and cooling, industrial processing, or for use indriving a steam turbine to generate more electricity.

A (high-temperature) fuel cell would consume the hydrogen and (primarilyin SOFCs) and carbon monoxide from the syngas provided by the GCS.Methane contained in the fuel gas would be partially reformed in ahigh-temperature fuel cell, resulting again in hydrogen and carbonmonoxide. The gas mixture exiting the fuel cell would likely stillinclude useful quantities of methane and carbon monoxide gases. Thesehot gases could be directed back into a regulation system or diverted tomore heat exchangers, which could be used for the production of steamthat is used in the converter.

Alternatively, hot but cleansed syngas can be input to a hightemperature hydrogen membrane filtering system to split the synthesisgas into two distinct gas streams. One stream is composed of purehydrogen and the other of pure carbon monoxide (CO). Carbon monoxide caneither be combusted in a gas-fired boiler to facilitate the recovery ofcarbon dioxide (CO₂) and the conversion of its potential energy insteam, or it can be transported to a compressor and bottled. Thehydrogen (H₂) can either be converted into energy in fuel cells or itcan be transported to a compressor and then fed into containers holdingeither/or a graphite nano-fiber storage medium or an anhydrous aluminumstorage medium, so that the H₂ can be safely stored or transported.

A hydrogen feed line can be provided from the high temperature hydrogenmembrane filtering system, to fuel cell stacks as a fuel supply to them.Fuel cell stacks of this system are of the molten carbonate type thatuse hydrogen gas at the anode and CO₂ at the cathode to produceelectricity. The carbon monoxide present in the syngas produces extrahydrogen as well as heat (up to 1500° F.) which can be recovered toproduce steam, carbon dioxide and water.

A carbon monoxide line may be provided to direct carbon monoxide fromthe high temperature hydrogen membrane filtering system to aconventional gas-fired boiler. The gas fired boiler combusts the CO sothat CO₂ and the potential energy value of the CO manufactured by thegasification system may be recovered more cost effectively.

Some upstream gasification systems will be designed for the input ofmore than one fuel or feedstock into the boiler, thereby providingversatility for increased amounts of power generation as required ordesirable. Examples of additional fuel sources include natural gas, aswell as the gases obtained from the anaerobic digestion of organicwastes (also referred to as biogas).

Depending on the specific electric power generating device selected, itmay be beneficial to include other types of fuel, in addition to thesyngas generated in the gasification system, to maximize the efficiencyof the electrical generator. Such additional fuels, indicated byoptional fuels, can include natural gas, oil, and other conventionalhydrocarbon-based fuels. It should be noted that the optional fuels arenot intended to provide the majority of the BTUs or energy consumed bythe electrical generators, but instead are included only when they canenhance the overall efficiency of the system.

An alternative configuration employs a gasification system that allowsfor the use of molten carbonate fuel cells, together with the productionof CO₂ and H₂O with greatly reduced emissions of oxides of nitrogen,carbon monoxide or unburned hydrocarbons. Instead of employing a gasfired boiler to make use of the carbon monoxide, the carbon monoxide isfed, along with hydrogen, to fuel cells. These fuel cells may be moltencarbonate or other types of fuel cells, which consume the carbonmonoxide as a valuable fuel.

Cooled pure hydrogen is ideal for use in proton exchange membrane fuelcell (PEMFC) stacks. As in other fuel cells, the chemical energy of thefuel is directly transformed into electricity. Electricity is generatedvia the following electrochemical reactions:

Anode: 2H₂=>4H⁺+4e ⁻

Cathode: O₂+4H⁺+4e ⁻=>2H₂O

These reactions occur at low temperature (<100° C.) and involvesplitting hydrogen into electrons and positive charged hydrogen ions(protons) at the platinum catalytic layer of the anode, passing protonsthrough the proton exchange membrane (electrolyte) and theirelectrochemical oxidation at the cathode catalyst. The electrolyte(solid polymer membrane) must be saturated with water and as a result acareful control of the moisture of the anode and cathode streams isrequired.

Moreover, low quantities of CO (higher than 1 ppm) and H₂S poisoncatalyst on the anode what renders strict requirements to the purity ofhydrogen. Comparing to other types of fuel cells, PEMFCs generate morepower for a given volume and weight and allow a rapid start-up. Thecontemporary efficiency of the PEMFC stacks reaches values of 35-45%.

A system can also be designed which allows the use of hydrogen gasdriven turbines to generate electricity without damage to criticalinternal components from the high combustion temperature of synthesisgas and greatly reduced emissions of oxides of nitrogen. The hydrogenfrom the high temperature hydrogen membrane may be input to a foggerwater injection system where de-ionized water is added before thecombination is burned in a gas turbine (or alternatively an internalcombustion engine) to convert the energy to mechanical force and drive agenerator which provides electricity. The water limits the internaltemperatures and thereby prevents heat damage to critical internalcomponents. In addition, the fogger water injection system makesoperation possible in locations and/or at times when such alternativefuels may not be readily available in quantity. In addition, the use ofthe irrigation fogger markedly lowers nitrous oxide emissions caused bythe high temperatures of the combustion of synthesis gas and/oralternative fuel mixes.

As is known in the art, the desired characteristics for syngas that isto be used in fuel cells can vary depending on the type of fuel cellused, as shown in Table 3 below.

TABLE 3 General Fuel Cell Characteristics Typical Operation AllowableConcentrations of Gas-Phase Constituents: Fuel Cell Type (° C.) CO CO₂Sulfur Hydrocarbons PEM 80  <5 ppm <50 ppm <1 ppm Restrictive^(a)Alkaline^(b) 120 <50 ppm^(c) <50 ppm^(c) <1 ppm <300 ppm Phosphoric 200<1% Diluent^(d) <1 ppm Diluent^(d) Acid Molten 650 Unrestricted^(e)Unrestricted^(e) <0.5 ppm   <10%^(f) Carbonate Solid Oxide 1000Unrestricted^(e) Unrestricted^(e) <1 ppm <10%^(f) ^(a)Variable dependingon construction, usually <100 ppm ^(b)Designed primarily for use withpure hydrogen and oxygen ^(c)Total CO + CO₂ concentrations <50 ppmrequired. Cell particularly sensitive to CO₂ ^(d)Serves primarily asdiluent; low concentrations preferred ^(e)Unrestricted within the rangeof values typical for gasification ^(f)Higher concentrations in the fuelstack impact economics due to dilution

Thus, in one embodiment where the fuel cell is an SOFC, the content ofHCl in the output syngas should be less than 1 ppm, the sulphur contentshould be less than 1 ppm, and the hydrocarbon content should be lessthan 10%.

In one embodiment where the fuel cell is an MCFC, the content of HCl inthe syngas is less than 0.5 ppm, the sulphur content should be less than0.5 ppm, and the hydrocarbon content should be less than 10%.

To gain a better understanding of the invention described herein, thefollowing examples are set forth. It will be understood that theseexamples are intended to describe illustrative embodiments of theinvention and are not intended to limit the scope of the invention inany way.

EXAMPLES Example 1 A GCS for Production of Conditioned Gas Suitable forUse in Gas Engines

The following example describes a GCS that is configured to produceconditioned gas suitable for use in gas engines. The GCS comprises thefollowing process operations:

Stage One Processes:

-   1. Evaporative Cooling (Quench)-   2. Dry injection system-   3. Particulate matter/heavy metal removal-   4. Processing of the solid residue in a solid residue gas    conditioner and associated solid residue GC

Stage Two Processes:

-   5. HCl Scrubber-   6. Process Gas Blower-   7. Gas Cooler-   8. Mercury polisher-   9. Sulphur Removal

The conditioned gas produced by the above process operations is storedand subsequently heated prior to use.

The above process operations are shown in FIG. 2 and described below. Ascan be seen from FIG. 2 the GCS employs converging process steps andcomprises a converter gas conditioner 4 integrated with a solid residuegas conditioner 5, as well as a solid residue conditioner 265. Syngasexiting from the converter 50 (input gas) is cooled using a heatexchanger 210 from approximately 1000° C. to about 740° C. prior tobeing fed into the GCS.

The output gas that results from processing through the GCS containsless than 17 mg/Nm³ particulate matter, less than 5 ppm HCl, and lessthan 10 ppm H₂S.

Stage One

Input gas particulate and heavy metal loading (mainly fly-ash with heavymetals) is as follows:

Design Gas flow rate—9500 Nm³/hrDust loading—7.4 g/Nm³Cadmium—2.9 mg/Nm³Lead—106.0 mg/Nm³Mercury—1.3 mg/Nm³

Guaranteed Stage One Output Gas Specifications:

Particulate matter—11 mg/Nm³ (about 99.9% removal)Cadmium—15 μg/Nm³ (about 99.65% removal)Lead—159 μg/Nm³ (about 99.9% removal)Mercury—190 μg/Nm³ (about 90% removal)

(1) Evaporative Cooling 220

After initial cooling in the heat exchanger 210, the input syngas isfurther cooled by dry quenching, which effectively lowers the syngastemperature and prevents condensation. Evaporative cooling is carriedout by an evaporative cooling tower 220 (dry quench) to bring down thesyngas temperature to about 260° C. (range 150° C. to 300° C.). This isachieved by direct injection of water into the gas stream in acontrolled manner (adiabatic saturation). This is a dry quench, andthere are controls to ensure that water is not present in the exitinggas and the relative humidity at the exiting gas temperature is,therefore, below 100%.

(2) Dry Injection System 271

Once the gas stream exits the evaporative cooling tower 220, activatedcarbon is then injected directly inside the gas stream, to remove heavymetals from the gas stream. The activated carbon is stored in a hopperand injected pneumatically into the gas stream. Carbon injectioncaptures most of the heavy metals and the spent carbon granules arecollected by the baghouse 230 and recycled back to the solid residueconditioner 265 for further energy recovery as described in the nextsteps. Activated carbon is injected in the gas with sufficient residencetime so that the fine heavy metal particles (cadmium, lead, mercury) areadsorbed on the activated carbon surface.

(3) Particulate Matter Removal

Particulate matter and activated carbon with heavy metal on its surfaceis then removed from the input syngas in the baghouse 230 with extremelyhigh efficiency, to provide an output gas that meets local metalsemissions limits and to protect the downstream gaseous contaminantremoval subsystems and the gas engines that will utilise the conditionedgas.

Particulate matter removal proceeds as follows. In the baghouse 230, afilter cake is formed with particulate matter on the fabric filters.This filter cake improves particulate removal efficiency of the baghouse230 operation. The baghouse 230 employs lined fibreglass bags, unlinedfibreglass bags, or P84 basalt bags and is operated at a temperaturebetween 200° C. and 260° C. The baghouse is thus designed for 99.9%particulate matter removal efficiency. Heavy metals like cadmium andlead are in particulate form at this temperature and are collected inthe baghouse with very high collection efficiency. A pulse jet ofnitrogen is used to clean the bags when the pressure drop across thebags increases to a certain set limit. Nitrogen is the pulsing gas inthis embodiment for safety reasons since air and syngas form anexplosive mixture.

The baghouse utilises cylindrical filters, which typically do notrequire any additional supports. The baghouse itself may be cylindricalor rectangular.

The operating parameter setup avoids any water vapour condensation.Special reagents such as feldspar can be used to absorb the highmolecular weight hydrocarbon compounds (tars) in order to protect thebaghouse. The gas exiting the Stage One processing is then processedthrough Stage Two processes.

(4) Processing of Particulate Matter in a Solid Residue Gas Conditioner265 and Associated Solid Residue GC 5

The quantity of solid residue contaminated with heavy metals exiting theconverter gas conditioner 4 is large and is, therefore, sent to a solidresidue conditioner 265 for conversion of the solid residue into slag.The gas created in the solid residue conditioner 265 is then treated ina solid residue gas conditioner 5 for removal of heavy metals by coolingin an indirect air-to-gas heat exchanger 270 and removal of particulatematter and heavy metals in a small baghouse filter 285. The smallbaghouse filter 285 is dedicated to treating gas from the solid residueconditioner 265. As shown in FIG. 2, additional steps carried out by thesolid residue gas conditioner 5 include cooling the gas further using agas cooler 290, and removing heavy metals and particulate matter in acarbon bed 295. The processed secondary syngas stream is then divertedback to the converter gas conditioner 4 to feed back into the inputsyngas stream prior to the baghouse filter step 230.

The quantity of solid residue removed from the small baghouse 285 of thesolid residue gas conditioner 5 is significantly less than that removedfrom the baghouse 230 in the converter gas conditioner 4. The smallbaghouse 285 acts as a purge for the heavy metals. The amount of heavymetals purged out of the solid residue gas conditioner 5 variesdepending on MSW feed composition. In general, only a periodic purge isrequired when the heavy metals build-up to a specified limit. As analternative to purging from the small baghouse 285 to hazardous wastedisposal, solid residue from the small baghouse can be re-circulatedback to the solid residue conditioner 265 for melting.

Design Specifications for Solid Residue Conditioner Baghouse 285:

Inlet Gas Particulate and Heavy Metal Loading (Mainly Fly Ash with HeavyMetals)Design Gas flow rate—150 Nm³/hrDust loading—50 g/Nm³Cadmium—440 mg/Nm³Lead—16.6 g/Nm³Mercury—175 mg/Nm³

Guaranteed Output:

Particulate Matter—10 mg/Nm³ (99.99% removal)Cadmium—13 μg/Nm³ (99.997% removal)Lead—166 μg/Nm³ (99.999% removal)Mercury—175 μg/Nm³ (99.9% removal)

Both the converter gas conditioner baghouse 230 and the solid residuegas conditioner baghouse 285 have a dust sensor on the exit (directfeedback or monitoring) to notify of a bag rupture. If a bag ruptureoccurs, the system may be shutdown for maintenance.

Stage Two (5) HCl Removal

After particulate matter is removed from the syngas in the converter gasconditioner 4, an HCl scrubber 240 is used for HCl removal. The HClscrubber 240 is located upstream of a gas moving means or process gasblower 245 for metallurgical considerations on the blower. The HClscrubber 240 can include an associated heat exchanger 241 as shown inFIG. 13. As shown in FIG. 13, the HCl scrubber 240 is a packed towerwhere almost all the HCl in the gas stream will react with are-circulating alkaline solution, NaOH as shown. A heat exchanger 241regulates the temperature of the system. The packed tower also providesenough contact area to cool down the gas to about 35° C. A carbon bedfilter 242 is used to separate potential soluble water contaminants,such as heavy metals, HCN, ammonia, tars and the like from the liquidsolution. The HCl scrubber 240 is designed for 5 ppm HCl outletconcentration. This reduces emission of HCl from engine exhaust of adownstream application up to 2 ppm. A waste water bleed stream is sentto a waste water storage tank for disposal. FIG. 14 shows an exemplarysystem for collecting and storing waste water from the GCS, in whichwaste water is collected from the HCl scrubber 240 and/or other upstreamprocesses in a sewer sump 70 and then fed into a waste water holdingtank 72. A waste water pump 74 is used to transfer waste water from theholding tank to the sewer or to a truck for transport offsite.

Design Gas flow rate 9500 Nm³/hr Normal Inlet/Max HCl loading toscrubber 0.16%/0.29% HCl outlet concentration 5 ppm

The water stream in the HCl scrubber 240 is analyzed at start-up toconfirm particulate matter removal efficiency.

(6) Process Gas Blower

After HCl is removed from the input syngas, a gas blower 245 is employedat this point to provide the driving force for the gas throughout theprocess from the exit of the converter 50 up to the engines of thedownstream application. It is located upstream of the mercury polisher250 because the polisher 250 has a better mercury removal efficiencyunder pressure. This also allows the size of the mercury polisher vesselto be reduced.

The blower 245 is designed using all upstream vessel design pressuredrops. It is also designed to provide the required pressure fordownstream equipment pressure losses to have a final pressure of ˜2.5psig in the gas storage tank (or “homogenization chamber”).

(7) Gas Cooler

As the gas is pressurized through the blower 245, its temperature risesto about 77° C. As the input gas passes through the gas cooler 246 thetemperature of the input gas is reduced back to 35° C. This is requiredfor the operation of the downstream H₂S removal system 260. The H₂Ssystem maximum design temperature is 40° C.

(8) Mercury Polisher

A carbon bed filter 250 is used as a final polishing device for anyheavy metal remaining in the input syngas stream. The carbon bedefficiency is improved when the system is under pressure instead ofvacuum, is at lower temperature, gas is saturated and HCl is removedfrom the gas so that it does not deteriorate the carbon. This additionalmetal removal step also provides the flexibility in controlling themetals in the system.

The performance of the mercury polisher is measured by analyzing the gasfor mercury. The monitoring does not need to be on-line and can simplyinvolve periodic verification by snap sampling. Corrections are made bymodifying the carbon feed rate and monitoring the pressure drop acrossthe polisher 250, and by analyzing the carbon bed efficiency viasampling.

The carbon bed filter is designed for over 99% mercury removalefficiency.

Design Gas flow rate—9500 Nm3/hrNormal/Max Mercury loading—190 μg/Nm3/1.3 mg/Nm3Carbon bed life—3-5 yearsGuaranteed mercury carbon bed outlet—19 μg/Nm3 (99%)

(9) Sulphur Removal

After additional heavy metals are removed in the mercury polisher 250,sulphur in the input gas is removed using an H₂S removal system 260. TheH₂S removal system 260 is based on SO₂ emission limitations outlined inA7 guide lines of the Ministry of Environment, Ontario, Canada. H₂Sremoval efficiency will be such that the gas leaving the GCS and beingcombusted in the gas engines will produce SO₂ emission below 15 ppm. TheH₂S removal system 260 is designed for 20 ppm H₂S outlet concentration(outlet of H₂S system). FIG. 15 shows an exemplary schematic diagram ofa suitable H₂S removal system 260 and associated components thatutilises Shell paques technology. Paques is a two step process: (1) H₂Sremoval from gas stream in an H₂S contactor 80, and (2) sulphurrecovery—This includes a bio-reactor 82 for oxidation of sulphide intoelemental sulphur, filtration of sulphur, sterilization of sulphur andbleed stream to meet regulatory requirements.

Input gas from the carbon bed filter 250 passes through a H₂S contactor80 where H₂S is removed from syngas by re-circulating an alkalinesolution. The sulphide containing solution from the scrubber is sent toa bio-reactor 82 for regeneration of alkalinity.

In the bio-reactor, Thiobacillus bacteria convert sulphide intoelemental sulphur by oxidation with air. A control system controls theairflow rate into the bio-reactor 82 to maintain sulphur inventory inthe system. A slipstream of the bio-reactor 82 is filtered into a filterpress. Filtrate from filter-press is sent back to the process, a smallstream from this filtrate is sent as a liquid bleed stream.

There are two sources of discharge; one solid discharge—sulphur withsome biomass and one liquid discharge—water with sulphate, carbonate andsome biomass. Both streams are sterilized before final disposal.

Design Gas flow rate—8500 Nm3/hrNormal/Max H₂S loading—353 ppm/666 ppmPerformance Guarantee Required after H₂S Removal System:Guaranteed H₂S outlet for system—20 ppm

Gas Storage and Gas Heating

The cleaned and cooled output syngas is transferred to a gas storagetank for storage.

The purpose of the gas storage tank is to homogenize its composition(heating value—LHV) and its pressure.

As gas engine design requires that the inlet gas be of a specificcomposition range at a specified relative humidity, prior to use, thegas can be passed through a chiller to condense the water out of thesyngas and sub-cools the gas from 35° C. to 26° C. The water condensedout from the input gas stream is removed by a gas/liquid separator. Thisensures that the gas has a relative humidity of 80% once reheated to 40°C. (engine requirement) after the gas storage prior to being sent to theengines.

The above-described GCS has the following specifications:

TABLE 4 GCS specifications Quench Tower quench gas from 740° C. to 200°C. in 2 sec residence time Activated Carbon 90% mercury removalefficiency Injection Baghouse 99.9% Particulate removal efficiency99.65% Cadmium removal efficiency 99.9% Lead removal efficiency HclScrubber 99.8% HCl removal efficiency Gas Blower zero leak seal rotaryblower Gas Cooler 0.5 MBtu/hr cooling load Carbon Bed Filter 99% mercuryremoval efficiency H₂s Scrubber H₂S at scrubber outlet - 20 ppm BioReactor Maximum regeneration efficiency with minimum blow-down FilterPress 2 days sulphur removal capacity Gas Storage Tank 2 min gas storagecapacity

The gas composition and condition of the input gas fed into the GCS asdescribed in this example and the conditioned gas that results fromprocessing through the GCS is shown in Table 5:

TABLE 5 Gas Composition and Condition before and after GCS Syngas Outletof Composition Unit Inlet to GCS GCS CH₄ ppm 215.00 242 CO % 15.10 17.00CO₂ % 7.82 8.80 COS ppm 21.00 0 H₂ % 16.00 18.01 HCl ppm 1,780.00 5 H₂O% 16.03 5.73 H₂S ppm 666.00 10 N₂ % 44.77 50.41 NH₃ ppm 8.00 0 S₂ ppm2.00 0 SO₂ ppm 7.00 0 Particulates mg/Nm³ 5,000.00 17

Example 2 Overview of a GCS Comprising Converging Process Steps

The following example provides an overview of a GCS which comprisesconverging process steps as shown in FIG. 9. In this example, the GCScomprises a converter gas conditioner 2 and a solid residue gasconditioner 3. in which a secondary gas stream generated in a solidresidue conditioner 165 is processed in a solid residue gas conditioner3 and then fed into the converter gas conditioner 2. In this example,the input gas has already been cooled prior to entering the GCS, forexample, in a recuperator.

Stage One Processes

Activated carbon 171 is injected into the input syngas stream, andparticulate matter and heavy metals are removed from the input gas usingparticle removal unit 130. The particulate matter and heavy metalremoved from the input gas is collected and transferred to the solidresidue conditioner 165 where it is converted to a solid residue and asecondary gas stream.

The secondary gas stream then enters a solid residue heat exchanger 170where it is cooled. In a subsequent step, activated carbon 172 isinjected into the secondary gas stream, and heavy metals or particulatematter in the secondary gas stream are separated from the secondary gasstream using particle removal unit 185. The secondary gas stream is thendirected back to the converter gas conditioner 2 where it enters and iscombined with the input gas stream after the particle removal unit 130of the converter gas conditioner 2.

Stage Two Processes

Still with reference to FIG. 9, once particulate matter and heavy metalsare removed from the input gas stream, the input gas stream combinedwith the secondary gas stream from the solid residue gas conditioner 3,is then directed to an HCl removal system 140 in which acid gases areseparated from the input gas. HCl is present in the syngas if thecarbonaceous feedstock used to generate the syngas in the lowtemperature gasifier includes chlorinated hydrocarbons.

In order to aid in the transfer of the input syngas from the HCl removalsystem 140 to the next process of the system, a gas moving unit 145 suchas a blower or other suitable unit is used. In this example, an optionalnext step in the GCS is to remove heavy metals in a heavy metal polisher150. The heavy metals and particulate matter removed in this step, alongwith those removed from the secondary syngas stream in the solid residuegas conditioner 3 are sent to a controlled landfill for disposal.

The next process as shown in FIG. 9 is also optional and is removal ofsulphur 160 from the input syngas. Sulphuric acid is present if thecarbonaceous feedstock used to generate the syngas in the converter iscoal with a high sulphur content. Sulphur that is removed is collectedand used in commercial applications. The output syngas is fed to adownstream application. Sulphur generated from this step can be furtherprocessed for use in commercial applications or for disposal.

Example 3 Overview of a GCS for High Temperature Gas Conditioning

This example describes a GCS for high temperature gas conditioning andprovides an example of a linear process sequence. An overview of theprocessing steps carried out by this GCS is shown in FIG. 3. At largecapacity applications, in order to improve the overall thermalefficiency, the syngas can be cleaned at temperatures as high as 760° C.The syngas exiting the converter 51 is cooled to approximately 760° C.in a heat exchanger 310. This cooled syngas (input syngas) then entersthe GCS 6. Particulate matter and heavy metals are then removed from theinput syngas in a cyclone separator or filter 330 (Stage One Process).The following Stage Two Processes are then carried out. A chloride guardbed 340 (Nahcolite) is used to remove HCl, followed by H₂S removal 360by sorbents. Finally, a ceramic filter 362 is used to remove anyparticles in the hot input syngas, prior to storage of the conditionedsyngas.

The GCS according to this example generates minimal amounts of liquidwaste (possibly the least of the examples as described in Examples 1,and 3 to 7) but may increase the amount of solid waste discharged, evenif the sorbents used for acid gas removal are regenerated.

Example 4 Overview of a GCS in which there is No Activated CarbonInjection Step

This example describes an overview of the processing steps carried outby a GCS as shown in FIG. 4, in which no activated carbon is injectedinto the system. This example incorporates a converging processsequence.

Input gas from a converter 52 is cooled with a heat exchanger 410 andthen enters a converter gas conditioner 8, where particulate matter isremoved from the input gas stream using a baghouse 430. Particulatematter collected from the baghouse 430 is sent to a solid residueconditioner 465 to produce a secondary gas stream and a solid residue.The secondary gas stream is then processed in a solid residue gasconditioner 7. The solid residue gas conditioner 7 carries out Stage Oneprocessing steps of cooling the secondary gas stream in an indirectair-to-gas heat exchanger 470 and removing particulate matter from thesecondary gas stream in a baghouse 485. Optional steps include gascooling 490 and removal of heavy metals and particulate matter in acarbon bed 495. The secondary gas stream is then fed back to theconverter gas conditioner 8 prior to the baghouse 430 and then flowsthrough the baghouse 430. The input gas is then processed in Stage Twoprocessing steps of acid gas removal in an HCl scrubber 440, followed byremoval of heavy metals and particulate matter in a mercury polisher450, and sulphur removal in an H₂S scrubber 460.

The distinctions between the GCS shown in Example 1 and the GCSdescribed in this example include:

-   -   A significant portion of the heavy metals pass through the        baghouse 430 and are partially absorbed in the liquid streams in        the subsequent subsystems, and eventually captured in the carbon        bed 450. The heavy metal loading in the aqueous streams is        higher than that observed for the GCS described in Example 1.    -   particulate matter loading decreases prior to baghouse 430    -   The amount of solids (ash) from the baghouse 430 is less than in        the GCS described in Example 1.

The liquid stream (waste water) resulting from this GCS described inthis Example has more contaminants such as heavy metals in it, ascompared to the GCS described in Example 1, thus increasing thepossibility that this liquid stream or waste water could be classifiedas hazardous waste and may require the use of a carbon filter on thewaste water, which can increase the cost of the system. In this example,the lifetime of the downstream carbon bed might be shortened due tohigher heavy metal loading, and more spent carbon will be generated,which will also be classified at hazardous waste if no regeneration isrequired.

Example 5 Overview of a GCS in which a Portion of the Cooled Syngas isRecycled

An overview of the processing steps carried out by a GCS in which someof the cooled gas processed through the GCS is recycled through thesystem is shown in FIG. 5. This GCS provides an example of a linearprocess sequence.

Stage One Processes

The input gas is a syngas which exits the converter 53 and is cooled ina heat exchanger 510. This input gas then enters the GCS 10 and iscooled in a dry quencher 520 as described in Example 1. Carbon 571 isinjected into the input syngas stream, and heavy metal and particulatematter are removed in a baghouse filter 530. The syngas exiting thebaghouse 530 is split into two streams. In one stream, up to 30% of thesyngas is recycled back to the exit of recuperator 510 (before dryquench 520) by the use of a blower 545. In this example, the cost andsize of the dry quenching tower and the amount of water consumed can beminimized. In the other stream, the syngas exiting the baghouse 530 isprocessed through Stage Two processes in which HCl is removed in an HClscrubber 540, followed by heavy metal and particulate matter removal ina carbon bed 550, and finally, H₂S removal 560.

In this example, less liquid waste is generated than in the GCSdescribed in Example 1, and the amount of solid waste generated isapproximately the same as that generated in Example 1.

Example 6 Overview of a GCS in which Particulate Matter is Removed fromthe Input Syngas at High Temperature

An example of a GCS in which particulate matter is removed from theinput gas in a high temperature Stage One process is shown in FIG. 6 anddiffers from the GCS described in Example 1 in that a high temperaturefilter (particle separator) 605, such as a cyclone, is used to removethe coarse particles from the syngas. This significantly reducesparticulate matter loading in syngas before the baghouse 630. Theremaining fine particles are collected by the baghouse 630. In thisexample, the secondary gas stream processed through the solid residuegas conditioner 9 is fed back to the converter gas conditioner 12 priorto the heat exchanger 610.

In this example, input syngas from a converter 54 is processed to removeparticulate matter at high temperature (Stage One Process) in a cyclonefilter 605. Syngas from the cyclone filter 605 can either be furtherprocessed in Stage One processes of cooling in a heat exchanger 610, andremoval of particulate matter and heavy metals in a baghouse filter 630,and then processed through Stage Two processes, or the syngas from thecyclone filter 605 can be fed directly to Stage Two processes of HClremoval 640, heavy metal and particulate removal in a carbon bed 650,and H₂S removal 660, prior to gas storage. In this example, the wastestream generated from the HCl scrubber 640 is treated by filtrationthrough a carbon bed 642 to remove heavy metals and particulate matter.

Particulate matter or ash from the baghouse 630 of the converter gasconditioner 12, is heated in the solid residue conditioner 665 toproduce a solid material and a secondary gas stream. The secondary gasstream is processed via Stage One processing steps including cooling inan indirect air-to-gas heat exchanger 670, followed by removal ofparticulate matter and heavy metals in a baghouse 685. Further optionalsteps include cooling of the secondary gas stream in a gas cooler 690,and removal of heavy metals and particulate matter in a carbon bed 695.The secondary gas stream is then fed back to the converter gasconditioner 12 prior to cooling of the gas in the heat exchanger 610.

In this example the quantities of both the liquid waste stream and solidwaste discharge are not significantly different from that of the GCSdescribed in Example 1. However, the lifetime of the baghouse filter isprolonged.

Example 7 Overview of a GCS which does not Include a Baghouse Filter forRemoval of Particulate Matter

An example of a GCS in which particulate matter is removed from theinput gas stream using a particle removal unit other than a baghousefilter is described as follows and shown in FIG. 7. This GCS provides anexample of a linear process sequence. As shown in FIG. 7, input gas isproduced in a converter 55 and cooled in a heat exchanger 710. The inputgas then enters the GCS 14. In this example, a baghouse is notincorporated into the Stage One processes of the GCS, but a hightemperature filter 705 (either cyclonic or ceramic) is employed toremove a portion or most of the particulates before the syngas isprocessed through Stage Two processes including wet quenching in a waterscrubber 740. Contaminants, which may include particulate matter, NH₃,HCN, HCl, tars and metals are absorbed in the liquid and treated in awaste water treatment facility. After the input gas is processed throughthe water scrubber 740, sulphur is removed in an H₂S removal system 760,and heavy metals and particulate matter are removed in a mercurypolisher 750.

In this example, large amounts of liquid waste containing thecontaminants noted above will be generated and these amounts of liquidwaste will require stringent treatment prior to disposal. The solidwaste (separated ash) may contain heavy metals, organics and otherinorganic species, and thus will be classed as hazardous waste, whichwill require the appropriate disposal procedures. As an optionalprocess, if the solid waste is fed back to a solid residue conditioner,the solid waste will first require dewatering and drying, which will addto the cost of operating the GCS.

Example 8 Overview of a GCS in which Conditioned Gas is not Used for theGeneration of Energy in Downstream Applications

FIG. 8 depicts an example of a GCS in which the output gas is not usedfor the generation of energy in a downstream application. The GCS 16 inthis example provides for the routing of the input gas through a StageOne process in which heavy metals and particulate matter are removedfrom the input syngas in a cyclone filter 830, followed by subsequentStage Two processing steps using: a venturi scrubber 842, an impinjetscrubber 844, a condenser, a baghouse filter 830, an orifice and theninto an exhaust mechanism. The GCS described here provides an example ofa linear process.

Example 9 A Municipal Solid Waste Gasification Plant Comprising a GCS

The GCS can be integrated with a plasma gasification system and/ordownstream applications. FIG. 10 depicts an overview process flowdiagram of municipal solid waste gasification plant comprising anexemplary GCS which is integrated with a downstream applicationinvolving gas engines. In this example, the solid residue gasconditioner 11 comprises a gas cooler 1090 and an activated carbon bed1095 after the baghouse 1085, and feeds back into the converter gasconditioner 18 prior to the baghouse 1030.

In this example, and with reference to the GCS shown in FIG. 10, inputgas from the converter 56 of the plasma gasification system is cooled ina recuperator 1010 and then processed through a converter gasconditioner 18 in Stage One processes of further cooling in a dry quenchprocess 1020, addition of activated carbon 1071 to the input gas stream,and removal of particulate matter and heavy metals in a baghouse 1030.The input gas is then processed through Stage Two processes includingHCl removal in an HCl scrubber 1040, removal of heavy metals andparticulate matter in a mercury polisher 1050 and H₂S removal in an H₂Sremoval system 1060. The material collected in the baghouse 1030 of theconverter gas conditioner 18 is sent to the solid residue conditioner1065 where it is converted to a solid residue and a secondary gasstream. The secondary gas stream generated in the solid residueconditioner 1065 is processed in a solid residue gas conditioner 11,through Stage One processes of cooling in an indirect air-to-gas heatexchanger 1070, removal of particulate matter in a baghouse 1085,followed by cooling in a gas cooler 1090 and additional heavy metal andparticulate matter removal in an activated carbon bed 1095. Thesecondary gas stream is then is fed into the converter gas conditioner18 where it is combined with the input gas stream prior to entry of theinput gas stream into the baghouse 1030 of the converter gas conditioner18. The input gas stream is then processed through the remaining StageOne and Stage Two processing steps of the converter gas conditioner 18.

Additional details of the process are described as follows:

Process Overview

The raw syngas exits the converter 56 and passes through a recuperator1010. The recuperator 1010 cools the gas and the sensible heat is usedto preheat the process air that is introduced into the converter 56. Thecooled syngas then flows into a GCS, where the syngas is further cooledand cleaned of particulates, metals and acid gases sequentially. The GCSin this example comprises a converter gas conditioner 18 and a solidresidue gas conditioner 11. The cleaned and conditioned syngas (outputgas, with desired humidity) is stored in the syngas storage tank 1062before being fed into gas engines 1063, from which electricity isgenerated. The functions of major components (equipment) in the systemare illustrated in the following sections (see Table 6), following thesequence that the syngas is processed. The equipment figure and processdiagram of the MSW gasification plant are presented in FIGS. 16 and 10,respectively.

TABLE 6 Main Function of Subsystem Subsystem or equipment Main FunctionRecuperator 100 Cool down syngas and recover sensible heat EvaporativeCooler (Dry Quench) Further cooling down of syngas prior to baghouse1020 Dry Injection System 1071 Heavy metal adsorption Baghouse 1030Particle or dust collection HCL Scrubber 1040 HCL removal and syngascooling/conditioning Carbon Filter Bed 1050 Further mercury removal H₂SRemoval System 1060 H₂S removal and elemental sulfur recovery Solidresidue gas conditioner 11 Slag chamber off-gas cleaning and coolingSyngas Regulation System Syngas storage, homogenization, and humidity(Homogenization Chamber, control Chiller and Gas/Liquid Separator GasEngines 1063 Primary driver for electricity generation Flare Stack 1064Burning syngas during start-up

Recuperator

In order to recover the syngas sensible heat, the raw syngas exitingfrom refining chamber is cooled by air using a shell-tube type heatexchanger, called a recuperator 1010. The syngas flows through the tubeside and the air passes through the shell side. The syngas temperatureis reduced from 1000° C. to 738° C. while increasing the air temperaturefrom ambient to 600° C. The input syngas then enters the converter gasconditioner 18.

Evaporative Cooler (Stage One Processing)

The evaporative cooler carries out the first step of the converter gasconditioner 18. The evaporative cooler 1020 drops Syngas temperature to250° C. via direct injection of water in a controlled manner (adiabaticsaturation). This process is also called dry quench in that there is noliquid present in the cooling. The water is atomized and sprayedco-currently into syngas stream. When the water is evaporated, itabsorbs the sensible heat from syngas and decreases the syngastemperature to approximately 250° C. before it is fed to the baghouse.

Dry Injection System (Stage One Processing)

The dry injection system 1071 injects activate carbon into the inputsyngas stream. Activated carbon has a very high porosity, acharacteristic that is conducive to the surface adsorption of largemolecular species such as mercury and dioxin. Activated carbon, storedin a hopper, is pneumatically injected into the input gas stream andcaptured in the baghouse 1030. In this way, the metals and othercontaminants are separated from the gas stream. Alternatively othermaterials such as feldspar, lime, and other sorbents can be injectedinto the gas stream to control and capture heavy metals & tars found inthe input syngas stream without blocking it.

Baghouse (Stage One Processing)

Particulate matter and activated carbon with heavy metal on its surfaceis removed from the Syngas in the baghouse 1030. In the baghouse 1030, afilter cake is formed with particulate matter. This filter cake enhancesthe particulate removal efficiency of the baghouse. Heavy metals likecadmium and lead are in particulate form at this temperature and arealso collected in the baghouse with very high collection efficiency.When the pressure drop across the baghouse 1030 increases to a certainset limit, nitrogen pulse-jets are used to clean the bags. The solidsfalling from the outside surface of the bags are collected in the bottomhopper and are sent to the solid residue conditioner 1065 for furtherconversion or disposal (see solid residue gas conditioner step below).

HCL Scrubber (Stage Two Processing)

The input syngas exiting from the baghouse 1030 (particulate free) isscrubbed in an HCl scrubber 1040 in a packed tower to remove HCl in thegas stream by an alkaline solution. Inside the scrubber 1040, there isenough contact area to cool down the gas to 35° C. The outlet HClconcentration will reach 5 ppm level. A waste water bleed stream is sentto a waste water storage tank for disposal.

Syngas Blower (Stage Two Processing)

A gas blower 1045 is required at this point to provide the driving forcefor the gas throughout the process from the exit of the converter 56 upto the engines 1063. It is located upstream of the mercury polisher 1050because the polisher has a better mercury removal efficiency underpressure. The blower 1045 is designed using all upstream vessel designpressure drops. It is also designed to provide the required pressure fordownstream equipment pressure losses to have a final pressure of ˜2.1 to3.0 psig in the gas storage tank 1062.

Carbon Filter Bed (Stage Two Processing)

The syngas pressure is boosted by a blower 1045 and further cooled by awater-cooled heat exchanger 1046 prior to the carbon bed filter 1050which is used as a final polishing device for heavy metal in the gasstream. It is also capable of absorbing other organic contaminants, suchas dioxins from the gas stream if present. The carbon bed filter 1050 isdesigned for over 99.0% mercury removal efficiency.

H₂S Removal System (Stage Two Processing)

After the input gas stream passes through the carbon filter bed, H₂Sremoval 1060 is carried out using Shell Paques Biological technology.Input syngas from the carbon bed filter 1050 passes through a scrubberwhere H₂S is removed from syngas by re-circulating an alkaline solution.Then, the sulfide containing solution from the scrubber is then sent tothe bioreactor for regeneration of alkalinity. The sulphur recoveryoccurs in the bio-reactor for oxidation of sulphide into elementalsulphur, followed by filtration of sulphur, sterilization of sulphur andbleed stream discharge to meet regulatory requirements. The H₂S removalsystem 1060 is designed for 20 ppm H₂S outlet concentration. Once theinput gas exits the H₂S removal system 1060 it is then directed to asyngas regulation system comprising amongst other components a chiller,a gas/liquid separator and homogenization chamber.

Solid Residue Gas Conditioner (Stage One Processing)

The material captured in the converter gas conditioner baghouse 1030(which may contain activated carbon and metals) is purged periodicallyby nitrogen and conveyed to the solid residue conditioner 1065, wherethe material is vitrified. The secondary gas stream coming out of thesolid residue conditioner 1065 enters a solid residue gas conditioner 11where it is cooled in a gas cooler 1070. The secondary gas stream isthen directed through the solid residue gas conditioner baghouse 1085 toremove particulates and then cooled by a heat exchanger 1090 beforeentering an activated carbon bed 1095 where heavy metals are removed.The baghouse 1085 of the solid residue gas conditioner 11 is alsoperiodically purged based on pressure drop across the system. The solidresidue collected in the solid residue gas conditioner baghouse 1085 isdisposed by appropriate means. The combustible gas (secondary gasstream) exiting from the solid residue gas conditioner 11 is sent backto the converter gas conditioner 18 to fully utilize the recoveredenergy.

Syngas Regulation System

The output gas exiting the GCS is stored in a syngas regulation system1062 prior to use as a fuel for gas engines. The gas engine designrequires that the syngas be of a specific composition range at aspecified relative humidity. Therefore, once the cleaned syngas exitsthe H₂S scrubber 1060, it is sub-cooled from 35° C. to 26° C. using achiller. This condenses some water out of the gas stream. This water isremoved by a gas/liquid separator. This ensures that the gas has arelative humidity of 80% once reheated to 40° C. (engine requirement)after the gas storage prior to being sent to the engines incircumstances where the output gas is used to power an engine. Thecleaned and cooled gas enters a homogenization chamber designed to holdapproximately 2 minutes of output from processing operations, thusblending any variations in “richness” of the gas, to achieve a highlyconsistent gas quality (a regulated gas) flowing to the engines. Thehomogenization chamber is operated at 2.2 to 3.0 psig to meet gas enginefuel specifications. Once the regulated gas exits the homogenizationchamber, it is heated to the engine requirement and directed to the gasengines 1063.

Gas Engines

Five GE Jenbacher gas engine sets 1063 are used to produce electricitybased on the scale of the plant. Jenbacher gas engine is a type ofreciprocating engine. It is capable of combusting low or medium heatingvalue syngas with high efficiency and low emissions. Each gas engine has1.0 MW capacity. So, the full capacity of electricity generation is 5MW. However, due to the relatively low gas heating value (as compared tofuels such as natural gas) the engines have been derated to operatearound 700 kW at their most efficient operating point.

Flare Stack

An enclosed flare-stack 1064 is used to burn syngas during start-up,shut-down and process stabilization phases. Once the process has beenstabilized the flare stack 1064 will be used for emergency purposesonly. The flare stack 1064 should achieve 99.99% destruction efficiency.

Example 10 A Municipal Solid Waste Gasification Plant Comprising a GCS

FIG. 11 depicts an example of a municipal solid waste gasification plantcomprising a GCS similar to that described in Example 9, with theexception that the secondary gas stream generated in the solid residueconditioner 1065 is processed in a solid residue gas conditioner 13 andfed into the converter gas conditioner 20 after the Stage One separationstep of removing particulate matter and heavy metals in the baghouse1030 of the converter gas conditioner 20, and is then processed throughStage Two of the converter gas conditioner 20.

Example 11 Overview of a GCS in which a Dry Scrubber and a Baghouse isUsed to Remove Particulate Matter

The following describes an exemplary gas conditioning system as shown inFIG. 17, in which a dry scrubber and a baghouse are used to removeparticulate matter from the input gas.

As shown in FIG. 17, input gas from a converter is first cooled in aheat exchanger 1710 prior to entering the GCS. The GCS in this exampleincludes the necessary equipment for injection of dry, activated carbonand sodium bicarbonate into the duct and baghouse 1730. The input gasafter dry scrubbing 1715 (Stage One processing) and particulate matterremoval in a baghouse 1730 (Stage One processing) is sent to wetscrubbing 1740 (Stage Two processing) mainly in a packed tower followedby a cross flow chamber 1760 as illustrated in FIG. 17.

In the dry scrubbing system 1715, a reagent containing powdered, dry,activated carbon and sodium bicarbonate is stored in bulk bagdischargers. A regulated amount of this reagent is injected into theduct through a pneumatic conveying system upstream of the baghousefilter 1730. The activated carbon adsorbs the heavy metals in the inputgas stream, and is carried with other particulates to the baghouse 1715.The particulates are collected on the exterior of the filter bags, andthe resulting dust cake further filters the input gas stream. The inputgas exiting from each fabric filter compartment is further cleaned andsub-cooled in a packed bed scrubber (wet scrubbing absorber 1740), inwhich HCl is removed from the input gas, and a cross flow chamber 1760,in which H₂S is removed from the input gas.

Functional and Technical Requirements of Equipment

The functional and technical requirements of the equipment describedabove are as follows:

Quench Reactor (Spray Dry Absorber)

The quench reactor or dry scrubber 1715 operates on a counter currentflow arrangement; hot syngas is quenched by cool alkaline solution fromthe packed tower solution oxidizing tank. In the quench reactor 1715some of the HCl present in the input gas is absorbed in the alkalinesolution, and salt is precipitated that is removed in the baghousefilter 1730.

Reagent and Activated Carbon Addition

Reagent and activated carbon is added to the input gas stream fromoverhead silos. A screw feeder and rotary feeder feeds this materialinto a mixing duct for mixing (reacting with input gas) before itreaches the baghouse filter 1730.

Baghouse Filter

Two baghouse filters 1730 each with 60% capacity with 3:1 air to Clothratio are used to avoid any unwanted shut down. During maintenance ofone of the baghouses the other baghouse can take full load with higherair to cloth ratio without damaging bags and reducing plant throughput.Each baghouse has isolation valves for isolation during maintenance.

A heating system is provided to maintain baghouse and bottom hoppertemperature above gas dew point all the time. Proper insulation isprovided to ensure no radiation heat losses.

Baghouse filters 1730 are cleaned intermittently based on pressure dropacross the filter with nitrogen (Pulse jet type baghouse).

Packed Tower (Absorber)

Gas from baghouse filter 1730 is absorbed in a counter current flowpacked bed absorber or wet scrubbing absorber 1740. The packed bedabsorber 1740 provides enough contact area and time for heat transferand mass transfer. An alkaline solution of sodium carbonate with 8.5 to9.5 pH ranges is re-circulated to scrub acid gases.

Cross Flow Chamber

Carbon dioxide in the input gas stream is acidic and has affinity toalkaline solution at higher pH (11.2-11.8), however H₂S cannot beabsorbed with higher efficiency at low pH. To balance between H₂Sabsorption and sodium carbonate consumption, the concept of a cross flowchamber 1760 is adopted. In a cross flow chamber 1760 sodium carbonatesolution with high pH is sprayed in cross flow pattern with input gas toreduce contact time and hence reducing the reaction with CO₂.

The sodium carbonate solution is prepared in a batch preparation tankwhere sodium carbonate is mixed with water in appropriate ratio to makean unsaturated sodium carbonate solution. This solution is supplied to ahigh pH feed tank which provides the solution to the cross flow chamber.

Heat Exchanger

Two heat exchangers one with 6.0 MBTU/hr (with cooling water as acooling medium) and other with 2 MBTU/hr (with sub-cooled water ascooling medium, for summer) remove heat from re-circulating solutions.

Oxidizing Tank

Scrubbing of hydrogen sulphide with sodium carbonate produces sodiumsulphides; this sulphide is converted into more stable form as sulphateby oxidizing it with air into a separate oxidizing tank 1750. Activatedcarbon is added as catalyst for this reaction.

In terms of liquid waste and solid waste discharge, the GCS described inExample 11 may have slightly higher solid waste discharge and liquidwaste discharge compared to the embodiment described in Example 1.

Example 12 High Level Process Control of a Municipal Solid Waste (MSW)Plant Comprising a GCS

This example provides a high level description of a control strategy foran MSW plant comprising a GCS. The high level process control includescontrol of components of the GCS. A 2 phase approach is used with regardto development and implementation of the process control strategy for anMSW plasma gasification plant:

Phase 1: Operation During Start-Up and Commissioning

For start-up and commissioning, a simple front-to-back (orsupply-driven) control strategy is used where the converter is run at afixed feed rate of MSW and process variations are absorbed by thedownstream equipment (engines/generators & flare). The plant is operatedwith a small buffer of excess syngas production, requiring a smallcontinuous flare. Syngas production beyond this normal amount increasesthe amount flared and deficient syngas production first eats into thisbuffer, but may eventually require generator power output to be reduced(generators can be operated from 50-100% power output via an adjustablepower set point).

The benefits of this control scheme are:

It is less complex. It improves the ability to start-up and commissionthe plant, and then to make use of the operating data to implement moresophisticated control. It decouples the back-end from the front-end suchthat problems with one section of the plant are less likely to cascadeto the rest of the plant. This increases the uptime and improves theability to troubleshoot and optimize each part of the process. The smallcontinuous flare eliminates the risk of large visible flame at the flarestack which can occur if the flare is operated in stop/start mode.

Phase 2: Long-Term Operating Strategy

The long-term control strategy for the MSW plant is to achieveback-to-front control (or demand-driven control) where the gasengines/generators at the back-end of the system drive the process. Thegas engines consume a certain volume/hr of fuel depending on the energycontent of the fuel gas and the electrical power being generated.Therefore the high level goal of the control system is to ensure thatadequate MSW/HCF feed enters the system and is converted to syngas ofadequate energy content to run the generators at full power at alltimes, while precisely matching syngas production to syngas consumptionsuch that flaring of syngas is eliminated and the electrical powerproduced per ton of MSW consumed is optimized.

A high-level process control schematic for Phase 2 operation is shown inFIG. 18. Phase 1 operation is a sub-set of the control schematic shown.

Phase 1 Operation—Main Process Control Goals:

a) Stabilize the pressure in the syngas storage tank.b) Stabilize the composition of the syngas being generated.c) Control pile height of material in the converter main chamber.d) Stabilize temperatures in the converter main chamber.e) Control temperatures in the converter refining chamber.f) Control converter process pressure.

Description of Each Goal a) Stabilize the Pressure in the Syngas StorageTank.

The GE/Jenbacher gas engines are intolerant of changes in supplypressure. The specifications are as follows: minimum pressure=150 mbar(2.18 psig); maximum pressure=200 mbar (2.90 psig); allowed fluctuationof fuel gas pressure=+/−10% (+/−17.5 mbar, +/−0.25 psi); maximum rate ofgas pressure fluctuation=10 mbar/sec (0.145 psi/sec). The engines havean inlet regulator that can handle small disturbances in supplypressure, and the holdup in the piping and homogenization chamber actsomewhat to deaden these changes, but this remains by necessity thefastest acting control loop on the converter.

The initial Phase 1 pressure control strategy is based on the operatingpremise that the converter is run at sufficient MSW feed rate togenerate a small buffer of excess syngas production, which is flaredcontinuously. Therefore the homogenization chamber pressure control is asimple pressure control loop where the pressure control valves in theline from syngas storage tank to the flare are modulated as required tokeep chamber pressure at the desired set point.

b) Stabilize the Composition of the Syngas being Generated.

The gas engines can operate over a wide range of fuel values, providedthat the rate of change is not excessive. The allowable rate of changefor Lower Heating Value is <1% fluctuation in syngas LHV/30 sec. For H₂based fuels, the fuel gas is adequate with as little as 15% H₂ byitself, and the LHV can be as low as 50 btu/scf (1.86 MJ/nm3). Forreference, typical LHV for the syngas produced is in the 4.0-4.5 MJ/nm3range. The system volume and homogenization chamber greatly simplify thetask of stabilizing the rate of change by providing mixing of about 2minutes worth of syngas production.

The gas composition is measured by a gas analyzer installed in the inletof the homogenization chamber. Based on this measurement the controllerwill adjust the fuel-to-air ratio (i.e. slightly increase/decrease MSWfeed rate) in order to stabilize the gas fuel value. Increasing eitherthe MSW or HCF feed relative to the air addition increases the fuelvalue of the gas. Note: Since this control action has a fairly longresponse time, it is tuned to only prevent long-term drift, not torespond to short-term variation.

While the HCF is by itself a much richer (˜2×LHV) fuel source, it istypically added in a 1:20 ratio with the MSW, and is not therefore thedominant player in terms of fuel being added to the system. It isuneconomical to add too much HCF to the system. HCF therefore is used asa trim and not as a primary control. HCF is ratioed to the total feedwith the ratio adjusted to stabilize the total C exiting the system inthe syngas, as measured by the gas analyzer. This dampens fluctuationsin MSW fuel value.

c) Control Pile Height of Material in the Converter Main Chamber.

A level control system is required to maintain stable pile height insidethe converter. Stable level control is needed to prevent fluidization ofthe material from process air injection which could occur at low leveland to prevent poor temperature distribution through the pile owing torestricted airflow that would occur at high level. Maintaining stablelevel also maintains consistent converter residence time.

A series of level switches in the converter main chamber measure piledepth. The level switches are microwave devices with a emitter on oneside of the vessel and a receiver on the other side, which detect eitherpresence or absence of solid material at that point inside theconverter.

The inventory in the vessel is a function of feed rate and ram motion(and to a lesser degree conversion efficiency. Stage 3 ram setsconverter throughput by moving at a fixed stroke length and frequency todischarge ash from the vessel. Stage 2 ram follows and moves as far asnecessary to push material onto Stage 3 and change the Stage 3start-of-stage level switch state to “full”. Stage 1 ram follows andmoves as far as necessary to push material onto Stage 2 and change theStage 2 start-of-stage level switch state to “full”. All rams are thenwithdrawn simultaneously, and a scheduled delay is executed before theentire sequence is repeated. Additional configuration may be used tolimit the change in consecutive stroke lengths to less than that calledfor by the level switches to avoid excess ram-induced disturbances.

The rams need to be moved fairly frequently in order to preventover-temperature conditions at the bottom of the converter. In addition,full extension ram strokes to the end of each stage may need to beprogrammed to occur occasionally to prevent stagnant material frombuilding up and agglomerating near the end of the stage.

d) Stabilize Temperatures in the Converter Main Chamber

In order to get the best possible conversion efficiency, the material iskept at as high a temperature as possible, for as long as possible.However, temperatures cannot go too high or the material will begin tomelt and agglomerate (form clinkers), which: 1) reduces the availablesurface area and hence the conversion efficiency, 2) causes the airflowin the pile to divert around the chunks of agglomeration, aggravatingthe temperature issues and accelerating the formation of agglomeration,3) interferes with the normal operation of the rams, and 4) potentiallycauses a system shut down due to jamming of the ash removal screw.

The temperature distribution through the pile will also be controlled toprevent a second kind of agglomeration from forming—in this case,plastic melts and acts as a binder for the rest of the material.

Temperature control within the pile is achieved by changing the flow ofprocess air into a given stage (ie. more or less combustion). Theprocess air flow provided to each stage in the bottom chamber will beadjusted to stabilize temperatures in each stage. Temperature controlutilizing extra ram strokes may also be necessary to break up hot spots.

e) Control Temperatures in the Converter Refining Chamber

Plasma torch power is adjusted to stabilize the refining chamber exittemperatures at the design set point (1000° C.). This ensures that thetars and soot formed in the main chamber are fully decomposed. Additionof process air into the refining chamber also bears part of the heatload by releasing heat energy with combustion of syngas. The flow rateof process air is adjusted to keep torch power in a good operatingrange.

f) Control Converter Process Pressure

Converter pressure is stabilized by adjusting the syngas blower's speed.At speeds below the blower's minimum operating frequency, a secondarycontrol overrides and adjusts the recirculation valve instead. Once therecirculation valve returns to fully closed, the primary controlre-engages. Additional description of these control is found below.

Phase 2 Process Control Goals:

For Phase 2 operation, all of the process control goals listed above aremaintained. However the key new requirements are to eliminate flaring ofsyngas and to optimize the amount of electrical power produced per tonof MSW consumed. This requires that the flow of syngas being producedmust exactly match the fuel being consumed by the engines. Thereforeback-to-front control (or demand-driven control) must be implementedwhere the gas engines/generators at the back-end of the system drive theprocess.

In order to stabilize syngas flow out of the converter, process airflowinto the converter is increased. Adjusting the rate of MSW or HCFaddition to the system eventually changes the syngas flow, but with a45+ minute residence time and no significant gasification reactionstaking place at the point of material entry, there is no chance of afast response due to these adjustments (it is expected that significantresponse may take about 15 minutes). Adjusting total airflow providesthe fastest possible acting loop to control pressure. In the short term,because of the large inventory of material in the converter, adding moreair to the bottom chamber does not necessarily dilute the gasproportionately. The additional air penetrates further into the pile,and reacts with material higher up. Conversely, adding less air willimmediately enrich the gas, but eventually causes temperatures to dropand reaction rates/syngas flow to decrease.

Total airflow is ratioed to material feed rate (MSW+HCF), so the meansof increasing air flow is to boost material feed rate. Controller tuningis set such that the effect of increased air is seen immediately.Controller tuning for feed rate is slower, but the additional feedeventually kicks in and provides the longer term solution to stabilizingsyngas flow. Optionally, temporarily reducing generator power output isrequired depending on system dynamics to bridge the dead time betweenincreasing the MSW/HCF feed rate and seeing increased syngas flow.

Control elements within the GCS are described as follows with referenceto FIG. 18. The control elements within the GCS as discussed hereintegrate with control elements through out the MSW plant to ensureefficient operation of the system. With reference to FIG. 18, atemperature sensing element 8106 is provided for sensing a temperaturewithin the solid residue conditioner 4220, wherein this temperature isat least partially associated with the output power of the solid residueconditioner plasma heat source 4230. It will be appreciated that othertemperature sensing elements may also be used at various pointsdownstream of the converter 1200 for participating in different local,regional and/or global processes. For example, temperature monitors mayalso be associated with the GCS to ensure gases conditioned thereby arenot too hot for a given sub-process, for example. Other such examplesshould be apparent to the person skilled in the art.

In controlling the residue processing within the solid residueconditioner, the power of the plasma torch 4230 may be adjusted asneeded to maintain temperatures adequate for the melting operation. Thesolid residue gas conditioner 4220 temperature instrumentation (e.g.temperature sensing element 8106) may include, for example, two opticalthermometers (OT's) which measure the surface temperature of the surfaceupon which they are aimed, 3 vapour space thermocouples mounted inceramic thermo wells above the melt pool, and 5 external skin mountedthermocouples mounted on the outer metal shell. The solid residue gasconditioner 4220 may also include a pressure transmitter for measuringprocess pressure (e.g. pressure sensing element 8112) inside the solidresidue gas conditioner 4220.

The pressure in the solid residue gas conditioner 4220 may be monitoredby a pressure transmitter tapped into the vapour space of the vessel(e.g. element 8112). In general, the operating pressure of the solidresidue gas conditioner 4220 is somewhat matched to that of theconverter gasification chamber such that there is minimal driving forcefor flow of gas through the screw conveyors in either direction (flow ofsolid residue particles only). A control valve (e.g. valve 8134) isprovided in the gas outlet line which can restrict the flow of gas thatis being removed by the downstream vacuum producer (syngas blower). ADCS PID controller calculates the valve position needed to achieve thedesired operating pressure.

Converter pressure and the pressure through the GCS may be stabilized byadjusting the syngas blower's 6250 speed. At speeds below the blower'sminimum operating frequency, a secondary control may override and adjusta recirculation valve instead. Once the recirculation valve returns tofully closed, the primary control re-engages. In general, a pressuresensor 8110 is operatively coupled to the blower 6250 via the controlsystem, which is configured to monitor pressure within the system, forexample at a frequency of about 20 Hz, and adjust the blower speed viaan appropriate response element 8113 operatively coupled thereto tomaintain the system pressure within a desired range of values.

Example 13 A Municipal Solid Waste Gasification Plant Comprising a GCS

FIG. 19 depicts an overview process flow diagram of a municipal solidwaste gasification plant comprising an exemplary GCS which is integratedwith a downstream application involving gas engines. In this example,the solid residue gas conditioner 15 does not include a gas cooler oractivated carbon bed after the baghouse 1985. The secondary gas stream,once it is processed through the solid residue gas conditioner 15 feedsinto the converter gas conditioner 24 prior to the baghouse 1930.

In this example, input gas from the converter 58 of the plasmagasification system is cooled in a recuperator 1910 and then processedthrough a converter gas conditioner 24 in Stage One processes of furthercooling in a dry quench process 1920, addition of activated carbon 1971to the input gas stream, and removal of particulate matter and heavymetals in a baghouse 1930. The input gas is then processed through StageTwo processes including HCl removal in an HCl scrubber 1940, processingof gas through a gas blower 1945 and cooler 1946, removal of heavymetals and particulate matter in a mercury polisher 1950 and H₂S removalin an H₂S removal system 1960.

The material collected in the baghouse 1930 of the converter gasconditioner 24 is sent to the solid residue conditioner 1965 where it isconverted to a solid residue and a secondary gas stream. The secondarygas stream generated in the solid residue conditioner 1965 is processedin a solid residue gas conditioner 15, through Stage One processes ofcooling in a gas cooler 1970, activated carbon addition 1972, andsubsequent removal of particulate matter in a baghouse 1085. Thesecondary gas stream is then is fed into the converter gas conditioner24 where it is combined with the input gas stream prior to entry of theinput gas stream into the baghouse 1930 of the converter gas conditioner24. The input gas stream is then processed through the remaining StageOne and Stage Two processing steps of the converter gas conditioner 24.

Additional details of the process are described below.

Process Overview

The raw syngas exits the converter 58 and passes through a recuperator1910. The recuperator 1910 cools the gas and the sensible heat is usedto preheat the process air that is introduced into the converter 58. Thecooled syngas then flows into a GCS, where the syngas is further cooledand cleaned of particulates, metals and acid gases sequentially. The GCSin this example comprises a converter gas conditioner 24 and a solidresidue gas conditioner 15. The output gas, a cleaned and conditionedsyngas (with desired humidity) is stored in the syngas storage tank 1962before being fed into gas engines 1963, from which electricity isgenerated. The functions of major components (equipment) in the systemare illustrated in the following sections (see Table 7), following thesequence that the syngas is processed. The process diagram of the MSWgasification plant is presented in FIG. 19.

TABLE 7 Main Function of Subsystem Subsystem or equipment Main FunctionRecuperator 1910 Cool down syngas and recover sensible heat EvaporativeCooler (Dry Quench) 1920 Further cooling down of syngas prior tobaghouse Dry Injection System 1971 Heavy metal adsorption Baghouse 1930Particle or dust collection HCL Scrubber 1940 HCL removal and syngascooling/conditioning Carbon Filter Bed 1950 Further mercury removal H₂SRemoval System 1960 H₂S removal and elemental sulfur recovery Solidresidue gas conditioner 15 Solid residue conditioner off-gas cleaningand cooling Syngas Regulation System Syngas storage, homogenization, andhumidity (Homogenization Chamber, control Chiller and Gas/LiquidSeparator) 1962 Gas Engines 1963 Primary driver for electricitygeneration Flare Stack 1964 Burning syngas during start-up

Recuperator

In order to recover the syngas sensible heat, the raw syngas exitingfrom refining chamber is cooled by air using a shell-tube type heatexchanger, called a recuperator 1910. The syngas flows through the tubeside and the air passes through the shell side. The syngas temperatureis reduced from 1000° C. to 738° C. while increasing the air temperaturefrom ambient to 600° C. The input syngas then enters the converter gasconditioner 24.

Evaporative Cooler (Stage One Processing)

The evaporative cooler carries out the first step of the converter gasconditioner 24. The evaporative cooler 1020 drops the input gastemperature to 250° C. via direct injection of water in a controlledmanner (adiabatic saturation). This process is also called dry quench inthat there is no liquid present in the cooling. The water is atomizedand sprayed co-currently into input syngas stream. When the water isevaporated, it absorbs the sensible heat from syngas and decreases thesyngas temperature to approximately 250° C. before it is fed to thebaghouse.

Dry Injection System (Stage One Processing)

The dry injection system 1971 injects activated carbon into the inputsyngas stream. Activated carbon, stored in a hopper, is pneumaticallyinjected into the input gas stream and captured in the baghouse 1930. Inthis way, the metals and other contaminants are separated from the gasstream. Alternatively other materials such as feldspar, lime, and othersorbents can be injected into the gas stream to control and captureheavy metals & tars found in the input syngas stream without blockingit.

Baghouse (Stage One Processing)

Particulate matter and activated carbon with heavy metal on its surfaceis removed from the input syngas in the baghouse 1930. In the baghouse1930, a filter cake is formed with particulate matter. This filter cakeenhances the particulate removal efficiency of the baghouse. Heavymetals like cadmium and lead are in particulate form at this temperatureand are also collected in the baghouse with very high collectionefficiency. When the pressure drop across the baghouse 1930 increases toa certain set limit, nitrogen pulse-jets are used to clean the bags. Thesolids falling from the outside surface of the bags are collected in thebottom hopper and are sent to the solid residue conditioner 1965 forfurther conversion or disposal (see solid residue gas conditioner stepbelow).

HCL Scrubber (Stage Two Processing)

The input syngas stream exiting from the baghouse 1930 (particulatefree) is scrubbed in an HCl scrubber 1940 in a packed tower to removeHCl in the input gas stream by an alkaline solution. Inside the scrubber1940, there is enough contact area to cool down the gas to 35° C. Theoutlet HCl concentration will reach 5 ppm level. A waste water bleedstream is sent to a waste water storage tank for disposal.

Gas Blower (Stage Two Processing)

A gas blower 1945 is required at this point to provide the driving forcefor the gas throughout the process from the exit of the converter 58 upto the engines 1963. It is located upstream of the mercury polisher 1950because the polisher has a better mercury removal efficiency underpressure. The blower 1945 is designed using all upstream vessel designpressure drops. It is also designed to provide the required pressure fordownstream equipment pressure losses to have a final pressure of ˜2.1 to3.0 psig in the gas storage tank 1962.

Carbon Filter Bed (Stage Two Processing)

The syngas pressure is boosted by the gas blower 1945 and further cooledby a water-cooled heat exchanger 1946 prior to the carbon bed filter1950 which is used as a final polishing device for heavy metal in thegas stream. It is also capable of absorbing other organic contaminants,such as dioxins from the input gas stream if present. The carbon bedfilter 1950 is designed for over 99.0% mercury removal efficiency.

H₂S Removal System (Stage Two Processing)

After the input gas stream passes through the carbon filter bed, H₂Sremoval 1960 is carried out using Shell Paques Biological technology.Input syngas from the carbon bed filter 1950 passes through a scrubberwhere H₂S is removed from the input syngas by re-circulating an alkalinesolution. The sulfide-containing solution from the scrubber is then sentto the bioreactor for regeneration of alkalinity. The sulphur recoveryoccurs in the bio-reactor for oxidation of sulphide into elementalsulphur, followed by filtration of sulphur, sterilization of sulphur andbleed stream discharge to meet regulatory requirements. The H₂S removalsystem 1960 is designed for 20 ppm H₂S outlet concentration. Once theinput gas exits the H₂S removal system 1960 it is then directed to asyngas regulation system comprising amongst other components a chiller,a gas/liquid separator and homogenization chamber.

Solid Residue Gas Conditioner (Stage One Processing)

The material captured in the converter gas conditioner baghouse 1930(which may contain activated carbon and metals) is purged periodicallyby nitrogen and conveyed to the solid residue conditioner 1965, wherethe material is vitrified. The gas coming out of the solid residueconditioner 1965 enters a solid residue gas conditioner 15, where it iscooled in a gas cooler 1970. Activated carbon 1972 is injected into thecooled gas which is then directed through a solid residue gasconditioner baghouse 1985 to remove particulates. The baghouse 1985 ofthe solid residue gas conditioner 15 is also periodically purged basedon pressure drop across the system. The solid residue collected in thesolid residue gas conditioner baghouse 1985 is disposed by appropriatemeans. The combustible gas (secondary gas stream) exiting from the solidresidue gas conditioner 15 is sent back to the converter gas conditioner24 where it feeds into this system prior to heavy metal and particulatematter removal in the baghouse 1930, to fully utilize the recoveredenergy.

Syngas Regulation System

The output gas exiting the GCS is stored in a syngas regulation system1962 prior to use as a fuel for gas engines. The gas engine designrequires that the output syngas be of a specific composition range at aspecified relative humidity. Therefore, once the output syngas exits theH₂S scrubber 1960, it is sub-cooled from 35° C. to 26° C. using achiller. This condenses some water out of the gas stream. This water isremoved by a gas/liquid separator. This ensures that the gas has arelative humidity of 80% once reheated to 40° C. (engine requirement)after the gas storage prior to being sent to the engines. The cleanedand cooled gas enters a homogenization chamber designed to holdapproximately 2 minutes of output from processing operations, thusblending any variations in “richness” of the gas, to achieve a highlyconsistent gas quality (a regulated gas) flowing to the engines. Thehomogenization chamber is operated at 2.2 to 3.0 psig to meet gas enginefuel specifications. Once the regulated gas exits the homogenizationchamber, it is heated to the engine requirement and directed to the gasengines 1963.

Gas Engines

Five GE Jenbacher gas engine sets 1963 are used to produce electricitybased on the scale of the plant. Jenbacher gas engine is a type ofreciprocating engine. It is capable of combusting low or medium heatingvalue syngas with high efficiency and low emissions. Each gas engine has1.0 MW capacity. So, the full capacity of electricity generation is 5MW. However, due to the relatively low gas heating value (as compared tofuels such as natural gas) the engines have been derated to operatearound 700 kW at their most efficient operating point.

Flare Stack

An enclosed flare-stack 1964 is used to burn syngas during start-up,shut-down and process stabilization phases. Once the process has beenstabilized the flare stack 1964 will be used for emergency purposesonly. The flare stack 1964 should achieve 99.99% destruction efficiency.

Example 14 A Municipal Solid Waste Gasification Plant Comprising a GCS

FIG. 20 depicts an example of a municipal solid waste gasification plantsimilar to that described in Example 13, except that the secondary gasstream generated in the solid residue conditioner 1965 and processed ina solid residue gas conditioner 17 is fed into the converter gasconditioner 26 after the Stage One processing step of removingparticulate matter and heavy metals in the baghouse 1930 of theconverter gas conditioner 26. The input gas stream is then processedthrough Stage Two of the converter gas conditioner 26.

Example 15 Specifications for Evaporative Cooling Tower, BaghouseFilter, HCL Scrubber, and Carbon Bed Filter

Examples of an evaporative cooling tower, baghouse filter, HCl scrubberand carbon bed filter that can be employed in the GCS described inExample 1 are provided below.

Evaporative Cooling Tower

Input gas from the heat exchanger or recuperator is cooled prior toentering the gas-solid filtration system (baghouse). This cooling isachieved by evaporative cooling (dry bottom quench) in order to minimizethe amount of water (liquid) going to the baghouse.

A redundant water supply system is designed in order to ensure thetemperature of the syngas exiting the quench tower never exceeds thedesign temperature of the baghouse. Quench water is provided from theHCl scrubber, at 35° C. The quench tower is located outdoors wheretemperature will be between −40° C. to 35° C. Table 8 describes thedesign specifications for the quench tower.

TABLE 8 Specifications of the Quench Tower Normal Inlet Pressure −0.3psig Normal/Max Inlet Temperature 740° C. (if recuperator is used)/1000° C. (if no recuperator) Desired Outlet Temperature 260° C.Normal/Max Inlet Flow 7950-9500 Nm³/hr Mechanical Design Vacuum/Pressure−2.5 psig/1.0 psig Mechanical Design Temperature 1100° C. MaximumAllowable Pressure Drop 5″ H2O

Selected Components of the Quench Tower:

1. Quench tower to achieve required cooling of the syngas to 260° C.2. Emergency water system to cool down the gas in case of pump failure.3. All the instruments with 4-20 mA signal or SMART transmitters, wiredto a junction box and all valves required for the operation of thequench tower.

Gas-Solid Filtration System (Baghouse Filter):

Table 9 provides a description of the characteristics of syngas flowingthrough the baghouse filter. Table 10 shows the composition of syngasflowing through the baghouse filter.

TABLE 9 Characteristics of syngas flow through baghouse filter: NormalInlet Pressure −0.48 psig Normal Inlet Temperature 260° C. Normal/MaxInlet Flow 11000-13200 Nm³/hr Mechanical Design Vacuum/Pressure −5psig/2.5 psig Mechanical Design Temperature 260° C. Maximum AllowablePressure Drop 5″ H₂O

TABLE 10 Gas composition of syngas flowing through baghouse filter GasComposition (v/v wet basis) CH₄ 182 ppm CO 12.10% CO₂  4.86% COS  7 ppmH₂ 13.55% HCl  0.14% H₂O 37.84% HS  <4 ppm H₂S 256 ppm N₂ 31.47% NH₃  7ppm SO₂  1.5 ppm

Inlet gas particulate and Heavy metal loading (Mainly fly-ash with heavymetals) in the baghouse filter is as follows:

Dust loading—7.4 g/Nm³Cadmium—2.9 mg/Nm³Lead—106 mg/Nm³Mercury—1.3 mg/Nm³Performance guarantee required after filtration system

Guaranteed Filtration System Outlet

Particulate matter—11 mg/Nm³ (99.9% removal)Cadmium—15 μg/Nm³ (99.65% removal)Lead—159 μg/Nm³ (99.9% removal)Mercury—190 μg/Nm³ (90% removal)

Selected Components of Baghouse Filtration System:

-   -   1. A single filtration unit operating 100% capacity.    -   2. Provision for double isolation to meet confined space entry        regulations and best practices. Acceptable examples include zero        leak isolation dampers (total two) and provision for inserting        blanking plate into duct to isolate module from process.    -   3. Nitrogen blow back system with nitrogen manifold to common        supply point.    -   4. High quality acid resistance, abrasion resistance filters        with temperature resistance of at least 260° C.    -   5. All instruments with 4-20 mA signal/or SMART transmitter        (wired to a junction box) required for operation of the system.        DCS provided.    -   6. Dust leak detectors (separate for each module).    -   7. Separate hoppers for each module with zero leak solid        discharge (rotary valves or equivalent).    -   8. All structural steel including ladders, access/maintenance        platforms required for both the units.    -   9. Activated carbon injection system with zero leak rotary valve        (Hopper will have capacity of 1.5 super sacks), bag unloading        system to hopper with required instruments.    -   10. Filtration system will be located outside where temperature        will be between −40° C. to 35° C.

HCl Scrubber

The HCl scrubber is designed to provide for the characteristics ofsyngas flowing through the HCl scrubber as shown in Table 11.

TABLE 11 Characteristics of syngas flowing through the HCl scrubberNormal Inlet Pressure −0.7 psig Normal Inlet Temperature 235° C.Normal/Max Inlet Flow 9500/11400 Nm³/hr Normal/Max HCl loading toscrubber (0.16%) 16.5 kg/hr/ (0.29%) 29.4 kg/hr Scrubber outlet gas maxtemperature 35° C. Scrubber outlet gas max relative humidity 100%Cooling water supply temperature 30° C. Mechanical DesignPressure/Vacuum −5 psig to 2.5 psig Mechanical Design Temperature 260°C./105° C. (Quench/Scrubber) Maximum Allowable Pressure Drop 3″ H₂O

A suitable HCl outlet concentration is 5 ppm.

Components of HCl Scrubber:

-   -   1. FRP (fibreglass reinforced plastic, or equivalent) packed        tower to achieve required removal efficiency of the HCl.    -   2. Heat exchanger (plate and frame—Titanium) to cool        re-circulating liquid stream to maintain gas temperature below        35° C. Cooling water supply and return. All controls required        for system operation.    -   3. Conductivity meter, pH control system, level control for the        scrubber system, two recirculation pumps (Online spare)    -   4. All the instruments (with 4-20 mA output signals), valves        required for the operation of scrubber, pumps are skid mounted        and instruments are wired to junction box. DCS provided.    -   5. Pumps and heat exchanger will be located inside a building        directly adjacent to column; however column will be located        outside.    -   6. Wet quench to cool down gas from 235° C. (design 260° C.) to        the HCl scrubber material requirements.    -   7. Emergency water system, to cool down gas in case of        circulation pump (both) failure.    -   8. All structural steel required for column/platform support,        pump and heat exchanger skid and piping support.    -   9. Scrubber outlet gas pipe to blower suction.

Carbon Bed Filter

The carbon bed filter is located after the product gas blower and isdesigned to accommodate the following characteristics of syngas flowingthrough it. These characteristics are summarised in Table 12 shows

TABLE 12 Characteristics of syngas flowing through the carbon bed filterNormal Inlet Pressure 3.0 psig Normal Inlet Temperature 62° C. (35° C.if a cooler is used prior to the carbon bed) Normal/Max Inlet Flow7200-8600 Nm³/hr Normal/Max Mercury loading 123 μg/Nm³/1.2 mg/Nm³Mechanical Design Pressure 5 psig Mechanical Design Temperature 105° C.Maximum Allowable Pressure Drop 6″ H₂O Carbon bed life 5 yearsGuaranteed mercury carbon bed outlet—19 μg/Nm³ (99.0%)

Components of Carbon Filter Bed

1. FRP carbon bed filter vessel with first carbon charge2. Structural steel required for vessel supports, inspection/maintenanceplatform, and provision for future carbon charging.3. All the accessories required for operation of carbon bed filters.

All the instruments have capability to interface with a gasificationcontrol system. The motor driven equipment is provided with on/offcontrols, lockable off button and status lines that will enable theequipment to be operated by a process control system.

Example 16 Specifications of an H₂S Removal System

The following Example provides a description of an H₂S removal systemthat can be implemented in the GCS described in Example 1. The H₂Sremoval system is designed to accommodate the characteristics of thesyngas flowing through it, as shown in Table 13. The composition ofsyngas flowing through the H₂S removal system is shown in Table 14.

TABLE 13 Characteristics of syngas flowing through the H₂S Removalsystem Normal Inlet Pressure 2.8 psig Normal Inlet temperature 35° C.Normal/Max H₂S loading 353 ppm/666 ppm Normal/Max Inlet Flow 7200-9300Nm³/hr Mechanical Design 5 psig Pressure/Vacuum Mechanical DesignTemperature 80° C. Maximum Allowable Pressure 10″ H₂O Drop

TABLE 14 Composition of syngas flowing through the H₂S removal systemGas Composition (v/v, wet basis) CH₄ 249 ppm  CO 18.4% CO₂ 7.38% COS 10ppm H₂ 20.59%  HCl 20 ppm H₂O 5.74% HS  4 ppm H₂S 353 ppm  N₂ 47.85% 

Normal Inlet gas particulate and Heavy metal loading data (Mainlyfly-ash with heavy metals) are listed below.

Dust loading—17 mg/Nm³Cadmium—14 μg/Nm³Lead—142 μg/Nm³Mercury—20 μg/Nm³Guaranteed H₂S outlet for system—20 ppm

During upset condition dust and heavy metal loading due to upstreamsystem failure is as follows.

Dust loading—1 g/Nm³Cadmium—1.3 mg/Nm³Lead—20 mg/Nm³Mercury—510 μg/Nm³

It is understood that during upset conditions, the presence of dust andheavy metal may cause foaming, and is dealt with by the injection of anantifoaming agent. An efficient antifoam system is used.

List of Components

-   -   1. H₂S Scrubber (contactor) with all associated accessories        required for the operation of packed column, column        recirculation pumps with (online spare), all instruments,        controls (pH, level and conductivity controller) and valves        (control and manual) required for scrubber operation and        isolation.    -   2. Inlet and outlet gas-liquid separator with automatic liquid        seal (liquid level) control to avoid any gas leaks—If required    -   3. Required nutrients tank and filtrate tank with all the        accessories, piping, valves and controls for continuous        operation and isolation of process.    -   4. Bio-reactor with complete control system required for        continuous operation of the system. Air blower with online        spare, instruments and controls including ORP controller, level        controller and valves (control and manual) required for        operation and isolation of the process.    -   5. Plate and frame or equivalent filter press for sulphur        removal from wet slurry. The filter is capable of operating        continuously for two days between two clean up/filter washings.        All instrumentation with valves required for operation and        isolation of the process.    -   6. Filtrate pumps with online spares, all controls valves and        manual valves required for the operation and isolation of        filtrate pumps.    -   7. A complete system required for treatment of bleed water (i.e.        UV filtration for bleed water) to meet Canadian Environmental        Protection Agency regulations, and future provision for        sterilization of solution before filtration to meet all        provincial and local regulations.    -   8. All instruments with 4-20 mA signal (wired to a junction box)        required for operation of the system. DCS also to be included.

Control Interfaces

A DCS is used for the entire process control. Optionally, a selecttransmitter with filedbus foundation protocol is used for easyintegration with the DCS.

Example 17 Characteristics and Design of a Product Gas Blower

The following is an exemplary description of a product gas blower (witha gas cooler) which can be used to withdraw syngas from a plasmagasification system and move it through the GCS. The blower providesadequate suction through all the equipment and piping as perspecifications shown below.

Functional Specifications

Functional specifications for the product gas blower are describedbelow. Syngas is flammable and will create an explosive mixture withair, therefore, all service fluid i.e. seal purge is done with Nitrogen.The blower is operated a through variable speed drive (VSD) within theflow range of 10% to 100%. Tables 15 and 16 show the designspecifications for the gas blower.

TABLE 15 Specifications of the gas blower Normal gas inlet temperature35° C. Normal gas suction pressure −1.0 psig Normal gas flow rate 7200Nm³/hr Maximum gas flow rate 9300 Nm³/hr Maximum gas suction temperature40° C. Normal discharge pressure 3.0 psig Normal discharge temperature(after gas <35° C. cooler) Mechanical design pressure 5.0 psig RelativeHumidity of gas at blower inlet 100% Gas Molecular Weight 23.3 Coolingwater supply temperature (product gas 29.5° C. cooler) Maximumacceptable gas discharge 40° C. temperature (after product gas cooler)Turn down ratio 10% Note: Pressure drop through suction and discharge ofthe blower is not included in the blower's static pressures

TABLE 16 Average gas composition flowing through the gas blower, on awet basis: Gas Composition, wet basis(v/v) CH₄ 0.03% CO 18.4% CO₂ 7.38%H₂ 20.59%  Normal/Max H₂S 354/666 ppm H₂O 5.74% Normal/Max HCl 5 ppm/100ppm N₂ 47.85% 

The blower is designed such that there is no air intake from atmosphere(can create explosive mixture) or gas leak to atmosphere (syngas istoxic and flammable). The blower has a very good shaft seal (0% Leak),and advanced leak detection system for leaks in both directions.

Components that May be Used

The following is a list of components that can be used with the productgas blower.

-   -   1. Syngas blower, motor is explosion proof. Blower shaft seal        zero leaks (does not leak).    -   2. Product gas cooler—the supplier scope of supply will be gas        cooler only    -   3. Auxiliary oil pump with motor, all required instrumentations        for blower auxiliary system    -   4. All instruments and controls (i.e. Low and high oil pressure        switch, high discharge pressure and temperature switch,        differential temperature and pressure switch, discharge pressure        gauge, discharge temperature gauge, oil pressure and temperature        gauge). All instruments are wired at common explosion proof        junction box. VFD will be controlled by pressure transmitter        installed upstream of the blower.    -   5. Zero leaks discharge check valve.    -   6. Equipment safety system to prevent blower from excessive        pressure/vacuum/shut off discharge (systems like PRV and recycle        line).

The blower is designed to work in an environment where explosive gasesmay be present in upset conditions.

The blower is operated continuously (24 hours per day/7 days per week),however there are chances of frequent start/stop operation of the blowerduring process stabilization. The gas blower is capable of working withhigh reliability even during frequent start/stop.

Control Interfaces

Variable speed drive for the motor control will be provided, as well asmotor over-voltage, overload protection etc. Motor status, On/Offoperation, speed change will be operated and monitored remotely throughDCS.

Although the invention has been described with reference to certainspecific embodiments, various modifications thereof will be apparent tothose skilled in the art without departing from the spirit and scope ofthe invention. All such modifications as would be apparent to oneskilled in the art are intended to be included within the scope of thefollowing claims.

1. A gas conditioning system for conditioning an input gas from one ormore locations within a gasification system to provide a conditionedgas, said gas conditioning system comprising: a. a first gas conditionercomprising one or more particle removal units for removing particulatematter from the input gas in a first conditioning stage to provide aconditioned gas and removed particulate matter; b. a solid residueconditioner for receiving and processing said removed particulate matterto produce a secondary gas and solid waste; and c. a second gasconditioner operatively associated with said solid residue conditioner,said second gas conditioner comprising a gas cooler and one or morefurther particle removal units for removing particulate matter from saidsecondary gas to provide a partially conditioned secondary gas, saidsecond gas conditioner configured to pass said secondary gas throughsaid gas cooler for cooling prior to entry of the secondary gas into theone or more further particle removal units and to pass said partiallyconditioned secondary gas to the first gas conditioner for furtherprocessing.
 2. The gas conditioning system according to claim 1, whereinsaid first gas conditioner further comprises one or more componentsdownstream of said one or more particle removal units for implementingfurther conditioning of the input gas in a second conditioning stage toremove additional contaminants from the input gas.
 3. The gasconditioning system according to claim 1, wherein said one or morelocations is a gasifier.
 4. The gas conditioning system according toclaim 1 or 2, wherein said first gas conditioner additionally comprisesat least one other component for implementing a dry phase processingstep in said first conditioning stage.
 5. The gas conditioning systemaccording to any one of claims 1 to 3, wherein one of said one or moreparticle removal units is a baghouse filter.
 6. The gas conditioningsystem according to claim 3, wherein said component for implementingsaid dry phase processing step is a dry injection system.
 7. The gasconditioning system according to claim 2, wherein said one or morecomponents comprise one or more components for acid gas removal.
 8. Thegas conditioning system according to claim 7, wherein said one or morecomponents for acid gas removal comprise an HCl scrubber.
 9. The gasconditioning system according to claim 7 or 8, wherein said one or morecomponents for acid gas removal comprise an H₂S removal system.
 10. Thegas conditioning system according to claim 2, wherein said one or morecomponents comprise a particle removal unit.
 11. The gas conditioningsystem according to claim 10, wherein said particle removal unit is anactivated carbon mercury polisher.
 12. The gas conditioning systemaccording to any one of claims 1 to 11, wherein said converter gasconditioner further comprises a blower for moving the input gas throughthe gas conditioning system.
 13. The gas conditioning system accordingto any one of claims 1 to 12, wherein said first gas conditioner furthercomprises a cooling unit upstream of said one or more particle removalunits.
 14. The gas conditioning system according to any one of claims 1to 13, wherein said second gas conditioner further comprises a coolingunit downstream of one or more further particle removal units, and anactivated carbon bed downstream of said cooling unit.
 15. A process forproviding a conditioned gas from an input gas from one or more locationswithin a gasification system, said process comprising the followingsteps: a. removing particulate matter from said input gas in a first gasconditioner in a first conditioning stage to provide a conditioned gasand removed particulate matter; b. transferring the removed particulatematter to a solid residue conditioner and melting the removedparticulate matter to produce a solid waste and a secondary gas; c.conditioning said secondary gas in a second gas conditioner by coolingand removing particulate matter from said secondary gas to provide apartially conditioned secondary gas; and d. transferring said partiallyconditioned secondary gas to said first gas conditioner for furtherconditioning.